NOAA Technical Memorandum NOS OR&R 44

Transporting Alberta Oil Sands Products: 

Defining the Issues and Assessing the Risks

Seattle, Washington

September 2013

DEPARTMENT OF COMMERCE • National Oceanic and Atmospheric Administration (NOAA)

National Ocean Service • Office of Response and Restoration
NOAA’s Office of Response and Restoration

NOAA’s Office of Response and Restoration (OR&R) is a center of expertise in preparing for, 

evaluating, and responding to threats to coastal environments, including oil and chemical 

spills, releases from hazardous waste sites, and marine debris.

To fulfill its mission of protecting and restoring NOAA trust resources, the Office of 

Response and Restoration:

• Provides scientific and technical support to prepare for and respond to oil and chemical

releases.

• Determines damage to natural resources from these releases.

• Protects and restores marine and coastal ecosystems, including coral reefs.

• Works with communities to address critical local and regional coastal challenges.

OR&R is comprised of three divisions: Emergency Response, Assessment and Restoration, 

and Marine Debris. Collectively, the Office of Response and Restoration provides 

comprehensive solutions to environmental hazards caused by oil, chemicals, and marine 

debris.

Cite as:

Crosby, S., et. al. 2013. Transporting Alberta Oil Sands Products: Defining the Issues and Assessing the Risks. 

U.S. Dept. of Commerce, NOAA Technical Memorandum NOS OR&R 43. Seattle, WA: Emergency Response 

Division, NOAA. 153 pp.
NOAA Technical Memorandum NOS OR&R 44

Transporting Alberta Oil Sands Products: 

Defining the Issues and Assessing the Risks

Shanese Crosbya,b ,Robin Faya,b, Colin Groarka,b, Ali Kanib,c, Jeffrey R. Smithb,d , Terry Sullivana,b, 

and Robert Paviae

a

Evans School of Public Affairs, University of Washington

b

Program on the Environment, University of Washington

c

Foster School of Business, University of Washington

d

School of Environmental and Forest Sciences, University of Washington e

School of Marine and Environmental Affairs, University of Washington

Gary Shigenakaf, Technical Editor

f

NOAA/NOS/ORR/ERD

NOAA Office of Response and Restoration

7600 Sand Point Way

Seattle, WA 98115

September 2013

Seattle, WA

U.S. DEPARTMENT OF COMMERCE

Penny Pritzker

Secretary

National Oceanic and 

Atmospheric Administration

Kathryn D. Sullivan, Ph.D.

Acting Under Secretary of Commerce for 

Oceans and Atmosphere, and Acting

Administrator

National Ocean Service

Holly A. Bamford, Ph.D.

Assistant Administrator for Ocean 

Services and Coastal Zone 

Management
DEPARTMENT OF COMMERCE

National Oceanic and Atmospheric Administration

National Ocean Service

Office of Response and Restoration

Emergency Response Division

Seattle, Washington, United States of America

Note on authorship

The first six authors contributed equally to the research, development, and writing of this report and are 

listed in alphabetical order. Robert Pavia was the project faculty advisor and as such was responsible for 

intellectual shaping of the project, conceiving and interpreting elements of the final paper and revising it 

critically for content.

Co-Authors’ Acknowledgments 

We would like to thank Mr. Gary Shigenaka of NOAA for his guidance and continued support. This 

project would not have been possible without his help and involvement. We would also like to thank 

the Program on the Environment at the University of Washington, and Doug Helton of NOAA for 

establishing this project and helping to guide it.

Scientists and responders from NOAA, the Washington Department of Ecology, and the U.S. Coast Guard 

were instrumental in the development and production of this report as well, and without their 

assistance, this final product would not have been possible. Thanks to all of you for the help and support 

during this process.

Technical Editor’s Acknowledgments

This project was originally conceived by Doug Helton of NOAA’s Emergency Response Division, but could 

not have been completed without the guidance and commitment of Dr. Robert Pavia, emeritus NOAA 

and presently UW faculty.

Many spill response personnel and environmental policy experts from around the U.S. and Canada 

kindly consented to assist the UW study team by sharing their expertise in person, by phone and by 

email. These included: Dr. Ed Owens, Dale Jensen, Linda Pilkey-Jarvis, LCDR Lance Lindgren, Ian Zelo, 

Jessica Winter, Dr. Robert Jones, Dr. Jim Farr, Steve Lehmann, Jay Lomnicky, Kurt Hansen, Lori Muller, 

Dr. Heather Dettman, and Dr. Todd Hass.

Editing, formatting, and graphics support was provided by Kristina Worthington.

Notice

This report has been reviewed by the Office of Response and Restoration and approved for publication. 

Such approval does not signify that the contents of this report necessarily represent the official position 

of NOAA or the government of the United States, nor does mention of trade names or commercial 

products constitute endorsement or recommendation for their use.
5 

EXECUTIVE SUMMARY

Oil sands are unconventional hydrocarbon deposits that consist of clay, sand, water, 

and a highly viscous petroleum product known as bitumen. Over the past decade, 

extracting bitumen from oil sands has become profitable as oil prices have increased and 

extraction technologies improved. With the rapid growth of the oil sands industry in 

Alberta, production is expected to grow from 1.25 million barrels per day (mbl/d) in 2011 

to around 3.75 mbl/d by 2030. Most oil sands products are transported to market via 

existing and proposed pipelines; however, a sharp increase in the use of rail and marine 

transport can be expected while new pipelines are constructed to match the increasing 

production of oil sands products.

Alberta bitumen owes its high viscosity and density to its geological origins. The 

deposits began as standard crude oil reserves, but over time the reservoirs never exceeded 

80̊ C, suggesting that pasteurization (sterilization) did not occur. Indigenous oil-degrading

microorganisms metabolized smaller molecules in the oil, leaving only the large molecules 

that impart the characteristic physical properties to bitumen. Bitumen densities can range 

from greater than to less than fresh water, complicating the question of whether the 

substance would sink or float if spilled in the environment. 

In order to transport bitumen, a diluent is usually added to decrease the viscosity and 

density. The most commonly used diluent is natural gas condensate, a liquid byproduct of 

natural gas processing. Typically, the mixture of diluent and bitumen (“dilbit”) consists of 

30% diluent and 70% bitumen. A second kind of diluent is synthetic crude oil (bitumen 

that has undergone partial upgrading, removing larger molecules through coking and 

hydrolysis), with the resulting bitumen-synthetic crude oil mixture called “synbit.” Synbit is

approximately 50% synthetic crude and 50% bitumen. Future projections indicate that the 

use of synthetic crude as a diluent will increase, while the use of natural gas condensate 

will remain steady because of natural gas condensate’s high price and decreased 

availability.

Little research is currently available regarding the behavior of oil sands products 

spilled into water, and how they weather in the environment. Most tests have been 

conducted in the laboratory, so predicting the actual behavior of oil sands products for a 

range of spills is difficult.

1 While the source bitumen can be denser than water (meaning 

that it would sink), with diluent addition the density of the mixture decreases to less than 

water (i.e., it would float). However, the ambient environmental conditions during a spill—

such as temperature, turbidity, water salinity, and mixing energy—can influence the 

tendency for oil sands products to float or sink. Responders to the 2010 oil sands product 

spill into the Kalamazoo River reported the presence of floating oil, submerged oil, and 

1 Recent tests conducted by industry have moved to mesocosm-scale experiments.

 
6 

sunken oil. There are several research projects to examine the weathering behavior of the 

spilled oil sands products, but results were not yet available at the time of this report. 

A highly debated topic related to oil sands products is the degree of corrosivity of 

mixtures and the implications for pipeline transport. Raw oil sands products tend to be 

higher in sulfur and total acid number than medium and light crude oils, which can 

contribute to corrosivity. However, the available research and monitoring suggest that oil 

sands products in their transported state are not more corrosive than standard crude oils, 

and thus do not pose a increased risk for transmission pipeline corrosion.

Environmental and human health risks are another concern associated with oil sands 

development and transportation. Conditions observed along the Athabasca River, near the 

oil sands deposits in Alberta, might be referenced during future oil spills. Researchers have 

found elevated levels of priority pollutants in the river below oil sands development 

exceeding those considered safe for aquatic life, but not exceeding those considered to be

safe for human consumption. However, distinguishing between toxicity attributable to 

bitumen, and that from seepage from tailings ponds is difficult. Fish larvae exposed to

bitumen-contaminated substances did show a higher rate of death and many of those that 

survived displayed physical abnormalities including lesions, hematomas, and unusual 

growths. Polynuclear aromatic hydrocarbons are elevated in the Athabasca River, but 

linkage to health effects has not been demonstrated. 

If a spill of oil sands products were to occur, responders could need to prepare for 

both a light, floating oil—depending on the diluent used—and the potential for a heavy, 

submerged or sinking oil. Species of concern for floating oil are any that frequent the 

interface between water and air, particularly those that may inhale toxic fumes from the oil 

sands products or the evaporating diluent, and/or those at risk from direct physical contact 

or coating. Submerged and sinking oil extends the potential for oil exposure into the water 

column, affecting fish and fish larvae, species that feed on or come into contact with 

sediments, and benthic habitats such as coral reefs.

For responders and residents of a spill-affected area, it is important to note that 

during the response to the Kalamazoo River spill, elevated benzene levels were measured

in the air. Also, bitumen tends to be higher in sulfur content, which may also distress 

exposed populations. The diluent, depending on the type, could pose additional issues 

related to relatively low flash point and flammability, as the gas is heavier than air. After 

the Kalamazoo River spill, 331 people reported adverse effects, including nausea, 

respiratory distress, and headaches—although none required hospitalization.

To date, only a handful of spills of oil sands products have occurred in the U.S. and 

Canada. In 2007, synthetic crude spilled in Burnaby, B.C. following a pipeline rupture. The 

second, in 2010, was the previously mentioned dilbit spill in Marshall, Michigan. In the 

latter example, a pipeline rupture led to dilbit spilling into the Kalamazoo River. The spilled 

dilbit initially floated, but eventually moved into the water column and sank to the bottom 

at natural collection points. The response efforts in Burnaby B.C. were considered to be 
7 

relatively successful, whereas the Kalamazoo spill response was more challenging. The 

cleanup effort is ongoing in the Kalamazoo River (as of March 2013). In both spills, the 

failure to follow emergency shutdown procedures increased the magnitude of the oil spills. 

More recent incidents involving Alberta oil sands products occurred in 2013. In 

March, an ExxonMobil pipeline burst near Mayflower, Arkansas, spilling Wabasca Heavy oil 

(a diluted bitumen product). In May, bitumen and water were discovered to be oozing to 

the surface near a production area in the Cold Lake Weapons Range in Alberta. A similar 

leak occurred in the same area in 2009. The causes of these Canadian spills remain

speculative, but the mode of production involves injection of high-pressure steam into the 

underground bitumen reserve and pumping the mobilized product to the surface.

Planning responses to spills of oil sands products is complicated by our inability to 

predict with certainty whether they will float, submerge, or sink. As of now, the ability to 

detect, monitor, contain, and recover submerged or sunken oil is limited. Research and 

development is currently underway to design equipment for responding to sinking or 

submerged oil spills. In addition, it is difficult to assess regional or national capacity to 

respond to a submerged or sunken oil spill as the existing equipment lists omit key pieces 

of information.

Regulations and standards governing oil spills can largely be divided into two related 

categories—requirements for preparing for oil spills and requirements for responding to 

oil spills. For oil sands products, several regulatory shortcomings were identified. Two 

important gaps are: 

• The exemption of oil sands products from the excise tax that provides funding for oil 

spill cleanup in the U.S.; and

• The unavailability of specific product information provided by facilities and 

transporters for the oil they are handling.

There are additional gaps in policies and regulations that warrant scrutiny as 

transport of oil sands products and other unconventional oils increases. Federal and state

railway regulators have previously played relatively minor roles in oil spill planning, but 

the rapid increase in rail transport of petroleum products and recent high-profile accidents 

involving oil and rail tank cars suggest the agencies with regulatory oversight over rail 

transportation should consider increasing effort for spill contingency planning

Concern has also been expressed that contingency plans for pipelines are not wellintegrated with regional and area spill contingency plans. Finally, while current regulatory

authorities permit agencies to oversee bitumen products, lack of resources and experience 

in dealing with potentially non-floating oils impede the ability to do so effectively. 
8

Contents

Executive Summary.............................................................................................................................. 5

1 Background.....................................................................................................................................15

1.1 Introduction to Oil Sands........................................................................................................................15

1.1.1 Reserves.............................................................................................................................................16

1.1.2 Production of Oil Sands Products............................................................................................17

1.2 The Economics of Oil Sands Products ...............................................................................................18

1.2.1 Economic Drivers...........................................................................................................................18

1.2.2 Main Economic Players on the Supply Side ........................................................................19

1.2.3 The Main Economic Players on the Demand Side ............................................................19

1.2.4 Who Benefits?..................................................................................................................................20

1.2.5 Economic Trade-offs.....................................................................................................................21

1.3 Environmental Impact of Oil Sands Products ................................................................................21

1.3.1 Greenhouse Gas Emissions ........................................................................................................21

1.3.2 Water-Use Impacts and Tailing Ponds ..................................................................................22

1.3.3 Land-Use and Wildlife Impacts ................................................................................................22

1.4 Modes of Transporting Crude Oil in North America ...................................................................23

1.4.1 Major Crude Oil Pipeline Networks in North America ...................................................24

1.4.2 Transport of Oil Sands Products via Rail..............................................................................27

1.4.3 Transport of Oil Sands Products via Waterways ..............................................................28

2 Spills of Oil Sands Products.......................................................................................................29

2.1 Recent Spills of Oil Sands Products ....................................................................................................30

2.1.1 Marshall, Michigan Enbridge Spill...........................................................................................30

2.1.2 Romeoville, Illinois Enbridge Spill..........................................................................................30

2.1.3 Burnaby, British Columbia, Kinder Morgan........................................................................31

2.1.4 Keystone Pipeline Spills ..............................................................................................................31

2.1.5 Mayflower, Arkansas, ExxonMobil Pegasus........................................................................32

2.1.6 Primrose Operations Area, Canadian Natural Resources LTD....................................32

3 Projections of Future Spills.......................................................................................................34

3.1 Does Transport of Oil Sands Products Increase Pipeline Spills?............................................34

3.2 Available Spill Risk Assessments.........................................................................................................34

3.2.1 Pipelines.............................................................................................................................................34

3.2.2 Rail .......................................................................................................................................................36

3.2.3 Waterways and Terminals .........................................................................................................36

3.3 Keystone XL Pipeline................................................................................................................................36

3.4 Northern Gateway Pipeline ...................................................................................................................38

3.5 Unimak Pass.................................................................................................................................................38
9

4 Transportation Methods............................................................................................................39

4.1 Pipelines ........................................................................................................................................................39

4.1.1 Networks of Crude Pipelines in North America ................................................................41

4.1.2 Regional Crude Pipelines in the U.S........................................................................................43

4.1.3 Diluent Pipelines ............................................................................................................................45

4.2 Rail Transportation...................................................................................................................................45

4.3 Marine Shipment........................................................................................................................................47

4.3.1 Puget Sound Waters – British Columbia to Washington ...............................................47

4.3.2 Strait of Juan de Fuca – British Columbia to Western U.S. States and Asia............47

4.3.3 Unimak Pass and the Aleutian Islands – British Columbia to Asia............................49

5 Properties, Fate, and Behavior of Oil Sands Products .....................................................51

5.1 Definition of Terms ...................................................................................................................................51

5.2 Chemical and Physical Differences between Raw Bitumen and Other Crudes ................52

5.2.1 Formation of Oil Sands.................................................................................................................52

5.2.2 Bitumen Chemical Properties...................................................................................................52

5.2.3 5.2.3 Bitumen Physical Properties..........................................................................................53

5.3 API, Specific Gravity, Acidity, and Other Data for Oil Sands Products .................................54

5.3.1 Floating, Sinking, and Submerged Oil....................................................................................54

5.3.2 Implications of Physical Properties in Spill Scenarios....................................................55

5.3.3 Information Gaps for Physical Properties............................................................................57

5.4 Diluents..........................................................................................................................................................57

5.4.1 Diluents and Synthetic Crude....................................................................................................57

5.4.2 Dilbit and Synbit Composition for Transport....................................................................58

5.4.3 Information Gaps for Diluents ..................................................................................................58

5.5 Weathering of Dilbit in the Environment ........................................................................................58

5.5.1 Weathering of Oil Sands Derived Products Relative to Conventional 

Heavy Crude Oils........................................................................................................................................58

5.5.2 Potential Weathering Patterns in the Environment........................................................59

5.5.3 Information Gaps for Modeling Weathering.......................................................................60

5.6 Corrosiveness of Oil Sands Products .................................................................................................60

5.6.1 Overview of Existing Research on Pipeline Corrosion...................................................60

5.6.2 Water and Sediment Content....................................................................................................61

6 Enivronmental and human health Effects of Oil Sands Products ................................63

6.1 Environmental Impacts...........................................................................................................................63

6.1.1 Species at Risk During Floating and Sinking Phase .........................................................63

6.1.2 Athabasca River Studies..............................................................................................................64

6.1.3 Information Gaps for Environmental Impacts...................................................................65

6.2 Human Health Impacts............................................................................................................................65

6.2.1 Human Health Concerns Near Oil Sands Products Development..............................65

6.2.2 Safety of Cleanup Crew and Citizens in the Spill Vicinity..............................................66

6.2.3 Information Gaps for Human Health Impacts ....................................................................67
10

7 Risk Mitigation ..............................................................................................................................68

7.1 Risk Mitigation Techniques ...................................................................................................................68

7.1.1 Pipeline Siting..................................................................................................................................68

7.1.2 Pipeline Modes of Failure and Leak Detection Technologies ......................................72

7.1.3 Information Gaps in Risk Mitigation Factors......................................................................76

7.2 Response Efforts.........................................................................................................................................76

7.2.1 Kalamazoo River Spill ..................................................................................................................77

7.2.2 Burnaby Harbor Spill....................................................................................................................79

7.2.3 Wabamun Lake Spill .....................................................................................................................80

7.2.4 Information Gaps in Response Efforts...................................................................................83

7.3 Effectiveness of Current Equipment on Sunken and Submerged Oil Spills .......................83

7.3.1 Assumptions.....................................................................................................................................83

7.3.2 Common Oil Spill Recovery Technologies and Anticipated Effectiveness .............84

7.3.3 Regional Response Capacity – Heavy Oil Spills .................................................................88

7.3.4 Information Gaps in Effectiveness of Current Equipment on Dilbit Spills .............90

7.4 Introduction.................................................................................................................................................91

7.5 Contingency Planning and Spill Response Background.............................................................91

7.5.1 Discharge of Oil Regulation........................................................................................................92

7.6 Federal Contingency Planning..............................................................................................................93

7.6.1 USCG....................................................................................................................................................93

7.6.2 USEPA .................................................................................................................................................94

7.6.3 DOT: Pipelines (PHMSA) and Rail (FRA)..............................................................................95

7.6.4 Federal Planning Regulations Specific to Group V Oils ..................................................99

7.7 Regional and State Roles in Contingency Planning and Response........................................99

7.7.1 Plans for U.S.-Canada Contingent Waters ............................................................................99

7.7.2 Regional Contingency Planning............................................................................................. 100

7.8 OSHA: Spill Response Planning Safety ........................................................................................... 103

7.8.1 Material Safety Data Sheets (MSDS).................................................................................... 103

7.9 Liability ....................................................................................................................................................... 103

7.9.1 USCG National Pollutions Funds Center and the Oil Spill Liability and 

Trust Fund ................................................................................................................................................. 104

7.10 Other Pertinent Regulations............................................................................................................... 104

7.10.1 Fish and Wildlife Coordination Act (FWCA)............................................................... 104

7.10.2 Marine Mammals Protection Act..................................................................................... 105

7.10.3 Endangered Species Act (ESA)......................................................................................... 105

7.11 Policy Gaps and Analysis...................................................................................................................... 105

7.11.1 Dilbit Excise Tax Exemption.............................................................................................. 106

7.11.2 Disclosing Oil Type and Characteristics ....................................................................... 106

7.11.3 Planning for Response to Group V Oils......................................................................... 107

7.11.4 Assessing Risks of Transportation Oil Sands Products.......................................... 107

7.11.5 Inconsistencies in Contingency Planning: PHMSA................................................... 107

7.11.6 Increased Transport of Oil by Rail.................................................................................. 107
11

8 Gaps and Recommendations ................................................................................................. 109

8.1 Policy............................................................................................................................................................ 109

8.1.1 Planning .......................................................................................................................................... 109

8.1.2 Transportation............................................................................................................................. 110

8.1.3 Response......................................................................................................................................... 111

8.2 Research ..................................................................................................................................................... 112

8.2.1 Physical Properties & Behavior of Dilbit...........................................................................112

8.2.2 Transportation Risks................................................................................................................. 113

8.2.3 Response Effectiveness ............................................................................................................ 113

8.2.4 Other Gaps...................................................................................................................................... 114

9 Appendices................................................................................................................................... 115

9.1 Appendix 1: Oil Sands Major Players List..................................................................................... 115

9.2 Appendix 2: Known Characteristics and Data Ranges for Alberta Oil Sands 

Products ...................................................................................................................................................... 130

9.3 Appendix 3: Analysis of Detection & Monitoring Equipment............................................... 131

9.4 Appendix 4................................................................................................................................................. 133

10 References.................................................................................................................................... 134
12

List of Figures

Figure 1-1: Existing North American Crude Oil Pipeline Network................................................. 25

Figure 1-2: North American Crude Oil Pipeline – Existing + Proposed ........................................ 26

Figure 1-3: WA Department of Ecology: Marine and Pipeline Routes in 

Puget Sound Region .......................................................................................................................................... 29

Figure 4-1 US DOT, PHMSA’s Petroleum Pipeline Systems ............................................................... 41

Figure 4-2 Map of Crude Oil Transport in Washington State ........................................................... 49

List of Tables

Table 1-1: Common Oil Sands Terms ......................................................................................................... 16

Table 1-2: North America's Existing Crude Oil Pipeline Network .................................................. 25

Table 1-3: North America's Proposed Crude Oil Pipeline Expansion............................................ 26

Table 1-4: Growth in use of Rail for Transportation of Crude Oil in North America............... 27

Table 3-1: Incident Rates Onshore Transmission Pipelines vs. Road and Railway 

(2005–2009)........................................................................................................................................................ 35

Table 3-2: National Pipeline Systems –Reported Incidents Summary Statistics: 

1993−2012 ........................................................................................................................................................... 35

Table 4-1: Crude Oil and Petroleum Products Transported in the US by Mode........................ 40

Table 4-2: Major Crude Pipelines Connecting Canadian Sources to the U.S. Destinations.... 43

Table 4-3: Summary of Major Diluent Pipelines.................................................................................... 45

Table 4-4: Scope of the VTRA Study Commissioned by Makah Tribe and Puget Sound ........ 48

Table 7-1. Status (as of March 2013) of proposed pipeline projects for transporting 

Alberta oil products. ......................................................................................................................................... 71

Table 7-2. Summary of detection and monitoring methods for sunken and submerged oil.85

Table 7-3. Summary of potential containment methods for sunken and submerged oil. ..... 86

Table 7-4. Summary of potential recovery methods for sunken and submerged oil. ............. 87

Table 7-5. Summary of potential transfer methods for recovered heavy oils. .......................... 88
13

Acronyms

ACP Area Contingency Plan

AER Alberta Energy Regulator

API American Petroleum Institute

ATM Unit of atmospheric pressure

Bbl Barrels

BNSF Burlington Northern Santa Fe

BS&W Water content measure

CAPP Canadian Association of Petroleum Producers

CN Canadian National Railway

CNOOC Chinese National Offshore Oil Corporation

CNRL Canadian Natural Resources Limited

COFR Certificates of Financial Responsibility

cP Unit of viscosity

CPR Canadian Pacific Railway

DEP Maine Department of Environmental Protection

DOT U.S. Department of Transportation

EFSEC Washington’s Energy Facility Site Evaluation Council

EIA Energy Information Administration

EIS Environmental Impact Statement

EPA U.S. Environmental Protection Agency

ESA Endangered Species Act

EU European Union

FOSC Federal On-Scene Coordinator

FRA Federal Railroad Administration

FRP Facility Response Plans

FWCA Fish and Wildlife Coordination Act

Gal Gallons

GCDWQ Guidelines for Canadian Drinking Water

CDP Gross Domestic Product

GHG Greenhouse gases

HCA High Consequence Area

IEA International Energy Agency

IM Integrity Management

IRS U.S. Internal Revenue Service

JCP Joint Contingency Plan

KOH Potassium hydroxide

LDS Leak Detection Systems

MARPOL International Convention for the Prevention of Pollution From Ships

MLV Main Line Valve

MMBO Million barrels of oil

MPC Marine Pollution Control

MSDS Material Safety Data Sheets
14

NCP National Contingency Plan

NEB National Energy Board

NEPA National Environmental Policy Act

NRT National Response Team

NOAA National Oceanic and Atmospheric Administration

NPFC National Pollution Funds Center

NPRA National Petrochemical and Refiners Association

NRDC Natural Resources Defense Council

NSFCC National Strike Force Coordination Center

NTSB National Transportation Safety Board

NWACP Northwest Area Contingency Plan

OGJ Oil & Gas Journal

OPA Oil Pollution Act

OPS Office of Pipeline Safety

OSC On-scene coordinator

OSHA Occupational Safety and Health Administration

OSLTF Oil Spill Liability and Trust Fund

PAC Polycyclic aromatic compounds

PADD Petroleum Administration for Defense District

PAH Polycyclic aromatic hydrocarbon

PHMSA Pipeline and Hazardous Materials Safety Administration

PPE Priority Pollutants

QI Qualified Individual

RAC Railway Association of Canada

RAMP Regional Aquatics Monitoring Program

ROVs Remotely operated vehicle

RRT Regional Response Team

SARA Superfund Amendments and Reauthorization Act

SCA Site Certification Agreement

SCAT Shoreline Cleanup and Assessment Technique

SCP Subarea Contingency Plan

SINOPEC China Petrochemical Corporation

SOLAS International Convention for the Safety of Life at Sea

SOPP Shipboard Oil Pollution Plans

TAN Total Acid Number

TM Trans Mountain

UC Unified Command

USCG U.S. Coast Guard

USFWS U.S. Fish and Wildlife Service

USGS U.S. Geological Survey

VOC Volatile organic carbon

WRRL Western Response Resource List
15

1 BACKGROUND

1.1 Introduction to Oil Sands 

Oil sands are unconventional hydrocarbon deposits that consist of clay, sand, water, 

and a highly viscous petroleum product known as bitumen. According to the U.S. Geological 

Survey (2006), oil sands is a “generic term that has been used for several decades” to 

describe this type of hydrocarbon deposit. Extracting bitumen from oil sands was, until 

recently, economically unfeasible, as bitumen is more difficult to extract and transport than 

conventional crudes oils due to its thick consistency and the need to dilute the oil for it to 

flow freely enough for transfer and transport. Over the past decade, extracting bitumen 

from oil sands has become profitable as oil prices have increased and extraction 

technologies improved.

The dramatic increase in the extraction of bitumen from oil sands deposits in the 

Canadian province of Alberta is just one part of a larger movement towards development of 

unconventional oils—those oils not extracted through conventional oil wells. According to 

the U.S. Department of Energy, unconventional oils are those that fall into one of three 

categories:

1. Petroleum-like material produced through heating the kerogen (the organic

chemicals found in sedimentary rocks) from oil shale deposits;

2. Bitumen extracted from oil sand deposits;

3. Low gravity crude oil from conventional reservoirs, but requiring heat for

production.

Although conventional oils have been historically less expensive to bring to market, 

extraction technologies have drastically reduced the price of producing unconventional 

oils. The production of the Alberta oil sands is just one example.

In this report we examine the issues associated with the transport of products derived 

from Alberta oil sands through the U.S., focusing on how this increased activity might 

change the calculus of spill risk in various ways. We begin with an introduction to oil sands 

production and transportation, highlighting the economic drivers of those activities and the 

environmental impacts in Alberta. The bulk of the report focuses on a number of the key 

issues, including a summary of past and projected spills of diluted bitumen and other oil 

sands products; a detailed outline of where oil sands products are being transported; the 

chemical and physical properties of oil sands products; an introduction to potential 

environmental and human health impacts of oil sands products; an outline of risk 

mitigation approaches in oil transport, planning, and spill response; and a summary of the 

regulations pertinent to oil transport and spills. We conclude with a summary of the gaps 

in information, research, and policy, and suggest some recommendations for how 

policymakers, researchers, and stakeholders might proceed in the future.
16

Common Oil Sands Terms2

Oil Sands or Tar Sands3 Used synonymously, the combination of bitumen, clay, sand, and water. EIA

(2013): “Naturally occurring bitumen-impregnated sands that yield mixtures 

of liquid hydrocarbon and that require further processing other than 

mechanical blending before becoming finished petroleum products.”

Bitumen A semi-solid or solid petroleum deposit. Thick like molasses at room 

temperature, it must be heated or diluted with lighter hydrocarbons to flow

(ENE, 2009).

Diluent Any “lighter viscosity petroleum products that are used to dilute bitumen for 

transportation in pipelines (CAPP, 2012). 

Synthetic Crude Also syncrude or SCO, according to CAPP (2012), “a mixture of hydrocarbons, 

similar to crude oil, derived by upgrading bitumen from oil sands.”

Dilbit Short for diluted bitumen, bitumen combined with any diluent for transport.

Synbit/Dilsynbit Bitumen combined with synthetic crude/and synbit combined with a diluent.

Oil Sands Products A term we use to describe products derived from oil sands, including bitumen, 

diluted bitumen, synthetic crude, synbit, and dilsynbit.

Table 1-1: Common Oil Sands Terms

1.1.1 Reserves

Twenty-three countries have known deposits of oil sands. The largest reserves are 

located in three major deposits in northern Alberta, Canada—the Athabasca, Cold Lake, and

Peace River deposits. The Government of Alberta estimates its total reserves of bitumen at

approximately 170 billion barrels (CAPP, 2012). Significant reserves also exist in 

Venezuela and Russia. U.S. reserves are small in comparison but contain twenty-nine 

accumulations totaling 36,000 MMBO4 (USGS, 2006). 

As of February 2013, bitumen is not being produced in the same quantity, quality, or 

with the same product specifications anywhere else in the world. However, there are three 

other countries that are producing products or will soon produce products similar to 

Canadian dilbit and synbit:

• Venezuela: Venezuela has bitumen reserves estimated to be 513 billion barrels of

recoverable oil located in the Orinoco Belt (USGS, 2009). Orimulsion is Venezuela’s

2 For a full glossary of oil sands terminology, visit: http://www.energy.alberta.ca/OilSands/1708.asp 

3 Oil sands and tar sands mean the same thing. They are used by different groups in order to frame the issue politically. 

We chose to use oil sands and oil sands products throughout this report for consistency and because it is more 

scientifically correct.

4 MMBO, million barrels of oil.
17

bitumen-based fuel, which consists of bitumen, 30 percent fresh water, and a small 

amount of surfactant (Rayaprolu, 2013). Orimulsion is not a homogenized mixture 

and the bitumen drops out of suspension when undisturbed for an extended period 

of time (Rayaprolu, 2013). Although it had been the focus of a major marketing 

effort in the U.S., orimulsion is not being exported to the United States, and 

Venezuela continues to decrease its orimulsion program due to political volatility 

(Rayaprolu, 2013).

• Kazakhstan: Russian oil company Gazprom Neft purchased a bitumen production

facility in Kazakhstan in January of 2013. The facility has an annual production

capacity of 280,000 tons (Energy Resources, 2013).

• Russia: Russian oil company Gazprom Neft is investing $446 million in renovating

the Moscow Oil Refinery to refine bitumen, and is expected to produce up to 1.7

million tons of product a year (Moscow Times, 2012).

1.1.2 Production of Oil Sands Products

Oil sands products are produced in two ways: surface mining and in situ recovery. 

The method employed depends on the proximity of the deposit to the surface. Surface

mining is generally used for deposits within 75 meters of the surface and requires the 

clearing of trees and topsoil before removing the oil sand deposits using industrial trucks 

and earth moving equipment. After removal, the oil sands are transferred to an on-site 

processing facility to remove the bitumen from sand and clay. Historically, surface mining 

has been the predominant method, but its share of production will significantly decline in 

the near future, as nearly 80 percent of remaining reserves are too deep to mine (Energy 

Information Administration, 2013). 

The second method of production, in situ recovery, refers to a method where two 

wells are drilled, one for a steam or solvent injection pipe and another to pump the 

separated bitumen to the surface. The steam separates the bitumen and also lowers its

viscosity, making it easier to pump to the surface, where it is blended with a diluent and 

transported via pipeline to an upgrading facility (NPR, 2012). 

1.1.2.1 Extraction and Upgrading

Extraction separates the bitumen from the oil sands. In situ extraction uses steam to 

separate the bitumen, while mining requires an additional step at an extraction facility. 

Here the oil sands are mixed with hot water—creating a slurry—and separated into sand, 

water, and bitumen, with the petroleum fraction sent to a primary upgrading facility by 

pipeline (NPR, 2012). According to the Energy Information Administration (EIA), “in order 

to flow in a pipeline, the bitumen must be diluted with condensate or other light oils or 

‘upgraded’ by complex processing units into a light, sweet ‘synthetic’ crude oil (SCO).” 

Upgrading is “the process by which heavy oil and bitumen are converted into lighter crude 
18

by increasing the ratio of hydrogen to carbon, normally using either coking or 

hydroprocessing”—and normally occurs in a two-step process (Alberta Energy, 2012). 

Of the total crude oil and equivalent production in Canada in 2011, roughly 28 percent 

was synthetic crude oil and 25 percent was non-upgraded crude bitumen (EIA, 2012). 

There were five upgrading facilities in Alberta where oil sands products were upgraded to 

synthetic crude oil in 2011 (Alberta Energy, 2012). Maps and information on oil sands 

deposits, extraction, and upgrading facilities can be found at 

http://environment.alberta.ca/apps/osip/

1.2 The Economics of Oil Sands Products

The oil industry has long been aware that large reserves of oil sands existed in Canada 

and parts of the United States. However, production of oil sands products is more difficult 

and expensive than production of conventional crude oils. The profitability of extracting oil 

sands products depends on a relatively narrow range of economic conditions. That is, crude 

oil needs to be priced at or above $65/barrel and possibly as high as $95/barrel in order 

for oil sands products to be profitable (Reuter et al., 2010). As conventional sources of 

crude oil have become scarcer and extraction technologies for oil sands products improved, 

the cost-benefit equation has shifted and oil sands products have become a more viable

commodity.

1.2.1 Economic Drivers

According to the International Energy Agency (IEA), the global supply of conventional 

oil already has or will soon peak, and only a dramatic increase in supply from nonconventional oil or renewable sources will prevent significant leaps in oil prices (IEA, 

2012). However, little has been done to substantively restructure economies to reduce 

dependency on oil, and until renewable energy sources are further developed and become 

commonly available as the status quo, the economic forces driving the extraction and 

refinement of oil sands will remain strong.

The United States and Canada continue to seek ways to achieve North American 

energy security and independence. According to Alberta Energy—the ministry that 

oversees Alberta’s non-renewable energy resources—Alberta supplies the U.S. with 1.4 

million barrels of oil a day from oil sands products (Alberta Energy, 2012). Although 

environmental objections have been fierce, it is an appealing justification in the U.S. to

import oil from a neighboring country that is considered as more stable and friendlier to 

U.S. political and economic interests than members of the potentially volatile OPEC5. 

5 Organization of the Petroleum Exporting Countries
19

1.2.2 Main Economic Players on the Supply Side

Canada is one of the world's five largest energy producers and is the principal source 

of U.S. energy imports (EIA, 2012). Oil sands products are a significant contributor to the 

recent and expected growth in the world's liquid fuel supply and comprise the vast 

majority of proven Canadian oil reserves, which rank third globally (after Saudi Arabia and 

Venezuela). Those reserves were estimated at 173.6 billion barrels at the beginning of 

2012 (EIA, 2013; Reuter et al., 2010). The Canadian government, on both a national and 

provincial scale, stands to increase Gross Domestic Product significantly by developing the

oil resources. Canadian companies Enbridge, Suncor, and Nexen are all heavily involved in 

the process (Reuters, 2012). American oil companies Exxon Mobil (Exxon Mobil also owns 

Imperial Oil and Esso), Shell, Conoco-Phillips, and Chevron are also invested in Canadian oil 

sands products. 

Chinese state-owned oil companies SINOPEC, the China National Petroleum Corp. 

(parent company of Petro-China), and the Chinese National Offshore Oil Corporation 

(CNOOC) are increasing their presence in Alberta (The Economist, 2012). Since 2005, 

CNOOC has been acquiring minority interests in Canadian oil companies, and recently 

acquired Calgary-based Nexen outright6 (Reuters, 2012; Armstrong, 2012). The U.S., China, 

and Canada currently comprise the major industrial stakeholders in Canadian oil sands 

deposits, but others may emerge on a smaller scale. For a more comprehensive list of the 

oil sands products major players, refer to the stakeholder list in Appendix 1. 

1.2.3 The Main Economic Players on the Demand Side

After extraction, bitumen can be blended with lighter grades of crude oil and is not 

necessarily identified as an oil sands product when transported (Owens, 2012). However, 

several major markets are receiving the majority of the oil sands petroleum originating in

Canada. The first, as might be expected, is the United States: the U.S. buys 2.5 million 

barrels of oil from Canada per day (Alberta Energy, 2012). For perspective, those 2.5

million barrels per day accounts for 18.2 percent of total U.S. oil consumption, exceeding

the 11 percent that the U.S. imports annually from Saudi Arabia (Consumer Energy Report, 

2012).

The other primary markets for oil sands products oil are in Asia (Gunn et al., 2012) 

and potentially Europe; although these supply lines are still less developed. China has 

shown great interest in Canadian oil development, and has already invested heavily in oil 

development capacity in Alberta. Additionally, Canadian Prime Minister Harper has spoken 

publicly about diversifying Canada’s export of oil to Asian markets. Although it is still a 

relatively small piece of the total exports, some tankers already carry Canadian oil to China 

from Canada’s west coast (Austen, 2011). As new terminals (e.g., the much-discussed 

facility planned for Kitimat, B.C.) come online, the transport of oil sands products through 

6 Final negotiations went through on 2/ 26. $15.1 billion deal approved.
20

U.S. and Canadian waters will increase dramatically. According to an investor presentation 

given by Ian Anderson, the President of Kinder Morgan’s Canada Group, tanker traffic in 

Port Metro Vancouver alone could increase to 288 visits annually by 2016, up from only 71 

in 2010 (Anderson, 2011). On the U.S. side of the border, tanker traffic in the Strait of Juan 

de Fuca is predicted by Kinder Morgan to increase from 4 tankers to 6 tankers daily, with a 

total increase of 500 tankers annually in the region (Kinder Morgan, 2013a). Other sources 

have also estimated as many as an additional 500 tankers a year moving through Puget 

Sound7 (Luk, 2012).

While Europe is a major oil importer, the European Union (EU) has been reluctant to 

open its markets to oil sands products (Carrington, 2012). In February 2012, the EU held a 

vote to determine if oil sands products should be considered as more polluting, which 

would have made them an infeasible energy source under current European climate 

policies. The vote ended in a stalemate, and it seems likely that Canadian lobbyists trying 

to open trade of oil sands products to Europe will continue to face resistance (Carrington, 

2012).

1.2.4 Who Benefits?

Oil companies enjoy significant profits from oil sands products. The oil industry, 

including American oil companies Exxon Mobil, Conoco Philips, and Chevron, have already 

invested significant resources and plan to invest an additional $120 billion over the next 

decade (Rainforest Action Network, 2012). As conventional crudes become scarcer, it is 

likely that oil prices will rise significantly, which may cause more aggressive pursuit of 

unconventional oils. Developing Canadian oil sands products reserves is one way that the 

industry can meet demand and prolong its ability to provide relatively cheap energy at a 

profitable level—though its success is not necessarily guaranteed.

The Canadian national and provincial governments would materially gain by

developing oil sands reserves, an objective that the current Conservative Party Prime 

Minister, Stephen Harper has made a national priority. That is, the Canadian economy 

benefits from revenues generated by sustaining the nation’s role as a significant oil 

exporter. At the provincial level, Alberta will reap the majority of the financial rewards. 

There have been disputes between Alberta and British Columbia over potential royalties 

B.C. would receive for allowing pipelines to cross the province. Twice, in 2010 and again in 

2012, B.C. municipal politicians have voted against the Enbridge Northern Gateway 

pipeline project, expressing the sentiment that while it may benefit Ottawa and Alberta, 

B.C. stands to gain little and bears most of the environmental risks (Market Wire, 2010; 

7 This increase is dependent on the approval and construction of the Enbridge Northern Gateway pipeline. According to 

some sources it is also contingent on additional new ports that would be built because of the new pipeline system, but 

according to Kinder Morgan the capacity already exists.
21

Huffington Post, 2012). Locally, mining areas like Fort McMurray have also experienced 

significant economic growth from the development of oil sands products.

Additionally, the United States would also benefit from oil sands products 

development. Industry advocates cite the statistic that for every two jobs created in 

Canada from oil sands products extraction, a third is created in the U.S. (Alberta Energy, 

2012). Alberta Energy claims “oil sands development is projected to generate $521 billion 

in economic activity in the U.S. over the next 25 years” (Alberta Energy, 2012).

1.2.5 Economic Trade-offs

Although the numbers differ depending on the source, it is clear that there are 

significant economic benefits associated with developing oil sands products. The dramatic 

increase in production has turned fur-trading outposts like Fort McMurray into boom 

towns, and has had wide reaching economic impacts through job creation, increased 

Canadian GDP, and large injections of revenue into the budgets of the federal, provincial, 

and local governments at a value estimated to be in the billions of Canadian dollars 

(Timilsina et al., 2005). However, these monetary gains must be evaluated against the 

disruptive impacts and environmental costs associated with bitumen extraction and 

increased spill risks (Skinner & Sweeney, 2012).

1.3 Environmental Impact of Oil Sands Products

Development and production of oil sands petroleum results in more negative 

environmental impacts relative to lighter crude oils. Heavier forms of oil, like bitumen, 

require more energy for extraction and processing, resulting in increased greenhouse gas 

emissions. In addition, oil sands extraction is more physically disruptive than conventional 

extraction techniques, leading to potentially significant local impacts in water use, land use, 

and on wildlife.8

1.3.1 Greenhouse Gas Emissions

Although all fossil fuel development results in greenhouse gas emissions—primarily 

carbon dioxide and methane—production of oil sands products is associated with higher 

emissions intensity. A number of studies have analyzed the overall emissions associated 

with oil sands products relative to other crude oils from a lifecycle perspective.9 These 

8 In addition, all crude spills pose potential environmental and health risks. Some organizations have expressed concern 

over the possible negative impacts of the diluents blended with oil sands in the event of a spill, namely higher exposure to 

hydrogen sulfide, benzene, and other toxins that affect humans and wildlife. These impacts are discussed in section 6.

9 See Alberta Energy Research Institute/Jacobs Consultancy, Life Cycle Assessment Comparison of North American and 

Imported Crudes, 2009; Alberta Energy Research Institute/TIAX LLC, Comparison of North American and Imported Crude 

Oil Lifecycle GHG Emissions, 2009; National Energy Technology Laboratory, Development of Baseline Data and 

Assessment of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels, November 26, 2008; National Energy 

Technology Laboratory, An Evaluation of the Extraction, Transport and Refining of Imported Crude Oils and the Impact of 

Life Cycle Greenhouse Gas Emissions, March 27, 2009.
22

analyses fall into one of two categories: “well-to-wheel” and “well-to-tank”. Well-to-wheel 

life-cycle assessments consider emissions from extraction, transportation, upgrading and 

refining, distribution, and combustion. Well-to-tank assessments focus on production and 

extraction. A survey of these studies by the Congressional Research Service found that 

Canadian oil sands products emit on average 14-20 percent (well-to-wheel) and 72-111

percent (well-to-tank) more greenhouse gases (GHG) than crudes they would displace in 

U.S. refineries (Lattanzio, 2012). The higher emissions intensity stems from two sources:

1. Mining: mining oil sands products requires more energy-intensive methods and in

situ methods use natural gas to heat steam; and

2. Extraction and Processing: extracting oil sands products requires more energyintensive methods due to the high viscosity of bitumen.

1.3.2 Water-Use Impacts and Tailing Ponds

One of the most pertinent local environmental concerns is water use and disposal. The 

extraction and processing of oil sands products requires large quantities of water, 

particularly in surface mining operations. For example, a barrel of produced oil sands oil 

requires approximately 3.1 barrels of net fresh water for mining and 0.5 barrels for in situ

(CAPP, 2012). After extraction, bitumen is separated from sand and clay by mixing it with 

warm water—and the water, clay, sand, and leftover oil (tailings) is moved to large storage 

ponds (CAPP, 2012). Some environmental concerns stem from the potential negative 

impacts on aquatic ecosystems from large tailings ponds, as well as from the removal of 

water from the watershed (Birn and Khanna, 2010).

Like all mining techniques, surface mining for oil sands generates tailings after 

separating the bitumen. As noted, the mixture of water, sand, clay, and residual bitumen is

sent to a tailings pond to be recycled. The tailings are placed in large pools that allow 

sediment to settle (which can take years), and the water skimmed off and reused. It is 

currently estimated that tailings ponds encompass an area of over 130 km2 in Alberta. A 

number of studies suggest that the efforts to manage the tailings ponds have been 

unsuccessful and that leakage, or ‘seepage,’ of toxic chemicals continues to occur at a high 

rate. A 2010 study showed that the oil sands industry “releases 13 elements considered 

priority pollutants (PPE) under the U.S. Environmental Protection Agency's Clean Water 

Act, via air and water, to the Athabasca River and its watershed”—seven of which exceeded 

Canadian standards for an aquatic environment (Kelly et al., 2010). 

1.3.3 Land-Use and Wildlife Impacts

The Canadian oil sands reserves are located within Canada’s boreal forest, part of the 

largest terrestrial ecosystem in the world. Like water use, land use impacts differ based on 

in situ extraction versus surface mining operations; however, both have negative 

implications for the land. Mining necessitates the removal of vegetation and topsoil; and
23

the topsoil is then stored for later use in the reclamation process. In situ extraction has a 

smaller footprint but still requires the construction of roads, pipelines, well pads, and 

facilities. According to the National Energy Board, “the proposed future reclaimed 

landscape will be significantly different—with 10 percent less wetlands, more lakes, and no 

peatlands.” The government of Alberta requires companies to restore land to at least its 

previous biological productivity, but reclamation requires a long time investment and its 

long-term success is subject to debate.

Wildlife organizations like the National Wildlife Federation argue that oil sands 

production has disrupted caribou and moose populations, with populations around Fort 

McKay decreasing 70 percent and 60 percent, respectively (NWF, 2012). For birds, the 

warm tailing ponds provide a seductively open but harmful body of water during the 

spring migration season when other bodies of water remain frozen, resulting in large 

numbers of bird deaths each year (Timoney & Lee, 2009).

1.4 Modes of Transporting Crude Oil in North America

The energy sector transports various crude oil, petroleum and natural gas products 

from source (e.g., wells) to destination (e.g. refineries and industrial complexes). This 

section briefly describes various modes of transporting oil sands products from source to 

destination. As Canada has been the main supplier of crude oil products to the U.S. since 

2010, (recall that the U.S. imports an average of 2.5 million barrels per day (mbl/d), or 27 

percent of total U.S. imports), for oil sands products the transportation story begins in the 

production areas of Alberta, and ends at various destinations in the United States. 

With the rapid growth of oil sands products in Alberta, production is expected to grow 

from 1.25 million barrels per day (mbl/d) in 2011 to around 3.75 mbl/d by 2030, an 

average annual growth rate of 11.5 percent (Canadian Province of Alberta [AB], 2012; 

Canadian Association of Petroleum Producers [CAPP], 2012). The majority of oil sands 

products transported to market will be via existing and proposed pipelines; however, a 

sharp increase in the use of rail can be expected while new pipelines are constructed to 

match the increasing production of oil sands products (CAPP, 2012; CNEB, 2009; CNEB, 

2006). 

The U.S. Department of Energy has divided the U.S into five regions for planning 

purposes. Each region is called a Petroleum Administration for Defense District (PADD). 

As of the 3rd quarter of 2012, the U.S. PADD II region (i.e., the Midwest) was the largest 

recipient with 1.6 mdl/d (71 percent), followed by PADD IV (Rocky Mountain states, 11

percent), PADD V (West Coast, 9 percent), PADD I (East Coast, 5 percent) and PADD III 

(Gulf Coast, 4 percent) (EIA, 2013; CNEB, 2012). The largest markets for synthetic crude oil 

in the U.S. were PADD II (76 percent) and PADD V (12 percent), while the largest markets 

for blended bitumen were PADD II (79 percent) and PADD III (10 percent) (EIA, 2013; 

CNEB, 2012). 
24

1.4.1 Major Crude Oil Pipeline Networks in North America

1.4.1.1 Existing Networks of Crude Pipelines

Canada’s main pipelines include Enbridge’s Mainline, Kinder Morgan’s Trans 

Mountain, and Kinder Morgan’s Express pipeline. This pipeline network has a capacity of 

roughly 3.5 million barrels per day (mbl/d) (Table 1-2) and runs through much of North 

America, connecting Canadian oil fields to transit ports and refineries in Canada and the 

U.S. (Figure 1-1) (CAPP, 2012; CNEB, 2009). 

The Enbridge system in Canada, combined with the Lakehead system in the U.S., is the 

world’s largest crude oil pipeline network (CAPP, 2012; CNEB, 2009). This network is the 

primary transporter of crude oil from western Canada to markets in eastern Canada and 

the U.S. Midwest for regional consumption and transfer to the other PADD regions. The 

system currently delivers about 2.1 mbl/d of crude oil products (including oil sands 

products). After future expansion, this capacity could increase to 3.5 mbl/d by 2020 

(subject to approval of Keystone XL pipeline in the U.S. Midwest – refer to section 4.1.1.3

for more information). The Mainline originates at Edmonton, Alberta, and meets with the 

U.S. Lakehead system at Sarnia, Ontario (CAPP, 2012; CNEB, 2009). 

The Kinder Morgan Express pipeline supports refineries in the U.S. West. The Express 

Pipeline system is batch-mode, in which the shipper receives the exact blend that it 

tendered for transport, and is comprised of the Express Pipeline and the Platte Pipeline. It 

connects Canadian and U.S. crude oil producers to refineries in PADD IV. The pipeline 

originates at Hardisty, Alberta, and terminates in Casper, Wyoming, with capacity of 0.28

mbl/d (CAPP, 2012). 

The Kinder Morgan Trans Mountain pipeline system, which directly affects 

Washington State’s energy portfolio, delivers Alberta oil to the Pacific Coast for use by U.S. 

refineries and export to Asian markets. The Trans Mountain pipeline transports crude oil 

and petroleum products from Edmonton, Alberta, to Vancouver, British Columbia, and an

offshore terminal via the Westridge Docks in British Columbia for customers in U.S. PADD V 

region and Asian markets (primarily China and Japan) with current capacity of 0.30 mbl/d

(CNEB, 2009). 

A subsection of the Enbridge pipeline network connects Canadian crude oil products 

from Sarnia, Ontario, to Montreal, Quebec, and then to Portland, ME for customers in U.S. 

PADD I (CAPP, 2012). 
25

Figure 1-1: Existing North American Crude Oil Pipeline Network (Credit: CAPP, 2013)

Table 1-2: North America's Existing Crude Oil Pipeline Network

Pipeline Network Crude Type Capacity 

(mbl/d)

Enbridge

Light 1.08 2.33

Heavy 1.25 2.33

TransCanada Light / Heavy 

(25% / 75%) 0.59

Kinder Morgan 

Trans Mountain

Light / Heavy 

(80% / 20%) 0.30

Kinder Morgan 

Express

Light / Heavy 

(35%/ 65%) 0.28

Total Existing Capacity 3.50

1.4.1.2 Proposed Crude Oil and Bitumen Pipelines

The U.S. and Canadian pipeline industries are currently working on many expansion 

proposals and construction projects (dotted lines in Figure 1-2) that will increase the 

current network capacity by 61 percent, to approximately 5.6 mbl/d (Table 1-3). The 

proposed Enbridge Southern Lights, Enbridge Northern Gateway, and Kinder Morgan 
26

Cochin Conversion are intended to transfer increased Canadian crude oil export to markets

in North American and Asia (CAPP, 2012; CNEB, 2009). 

Figure 1-2: North American Crude Oil Pipeline – Existing + Proposed. (Credit: CAPP, 2013)

Table 1-3: North America's Proposed Crude Oil Pipeline Expansion

Pipeline Crude 

Type

Capacity

(mbl/d) Origin Destination Consumer Markets

Year 

Active

TransCanada

Keystone XL 

Light/ 

Heavy/ 

Diluent

0.33 Hardisty, AB Steele City, NE PADD III 2016

0.55 Cushing, OK Nederland, TX PADD III 2014

Enbridge 

Northern Gateway

Heavy/ 

Diluent 0.53 Kitimat, BC Edmonton, AB Asia 2017
27

Pipeline Crude 

Type

Capacity

(mbl/d) Origin Destination Consumer Markets

Year 

Active

Kinder Morgan 

Trans Mountain 

Expansion

Heavy 0.45 Edmonton, 

AB Burnaby, BC PADD VAsia 2017

Enbridge

Alberta Clipper & 

Southern Light 

Expansion

Heavy/ 

Diluent 0.12 Flanagan, IL Edmonton, AB PADD II 2014

Enbridge 

Line 9 Reversal

Light/ 

Heavy/ 

Diluent

0.10 Montréal, 

Québec Sarnia, ON

PADD I

Europe

2014

Kinder Morgan 

Cochin Conversion Diluent 0.07 Kankakee 

County, IL

Fort 

Saskatchewan, 

AB

Alberta 2014

Total Proposed Capacity 2.15

1.4.2 Transport of Oil Sands Products via Rail

Rail is becoming an increasingly larger proportion of the crude oil transportation

network because companies can increase their carrying capacity relatively quickly by 

buying more railcars—and because the freight rail infrastructure is already in place 

throughout North America. Rail transport of all types of crude oil products increased 

roughly 55 percent in the year between March of 2011 and March of 2012 (Table 1-4) (CN, 

2012). Rail is increasingly relied upon to provide a short-term alternative to pipelines, as it 

allows companies to increase production and transportation without investing in

significant new infrastructure; however, with its logistical limitations, it remains to be seen 

how much of crude oil transport will be allocated to rail in the long term. Recent 

catastrophic rail accidents involving the transport of oil may also alter the distribution 

profile for bulk oil movement.

Table 1-4: Growth in use of Rail for Transportation of Crude Oil in North America

Date

Rail Cars

(#)

Weight

(Metric Tons)

March-12 8,823 707,647

March-11 5,602 458,696

Growth Rate 57% 54%
28

Canada’s two major rail companies, Canadian National (CN) and Canadian Pacific 

(CPR), are positioned to benefit from increased oil production in Alberta. Both companies 

own tracks as far north as the Alberta oil sands fields, and are already major transporters 

of mining and in situ extraction supplies for the oil companies. CN and CPR have an 

extensive North American network that could support increased transport of crude 

products from the source to refineries and shipping ports (CN, 2012; CPR, 2012). 

In anticipation of the growth in transportation volume, rail companies are studying 

several options to reduce their transportation costs and increase the effectiveness of rail 

transport as an alternate to pipelines. These include (CAPP, 2012): 

• Test runs transporting light crude and condensate from California, Texas, and

Louisiana;

• Evaluating the potential of using heated rail cars to transport non-upgraded

bitumen that could then be blended to specifications at terminals near the

destination refineries. Heated railcars would allow for speedier loading and

unloading of high viscosity oil sands products;

• The transportation of Alberta oil sands products by electric rail to an existing

marine terminal at Valdez, Alaska for Asian markets.

1.4.3 Transport of Oil Sands Products via Waterways

In anticipation of tremendous growth in the production and need for transportation 

of oil sands products, and due to uncertainties in development of new pipelines, oil 

transport companies are exploring the option of increased shipping of oil sands products

via barges through North American waterway networks, specifically the Mississippi River 

for U.S. PADD II and III markets (Break Bulk I, 2011; Break Bulk II, 2011; Gabriela Alcocer; 

Seana Lanigan, 2012). The option of using barges in North American waterways will likely 

be a viable alternative on the Pacific Coast (e.g., Puget Sound) and the Great Lakes region, 

where waterway distances between crude terminal and refineries are relatively short

(Jensen and Pilkey-Jarvis, 2012). There are currently shipments of heavy and extra heavy 

crude oil products via barges from terminals in British Columbia to Puget Sound refineries 

in Anacortes and Tacoma (Figure 1-3) (Jensen and Pilkey-Jarvis, 2012). 
29

Figure 1-3: WA Department of Ecology: Marine and Pipeline Routes in Puget Sound Region (Credit: WA 

Department of Energy (DOE), 2012)

2 SPILLS OF OIL SANDS PRODUCTS

Five significant spills of diluted bitumen have occurred in the U.S. and Canada over the 

past two and a half years. These include spills from Enbridge pipelines in Michigan and 

Illinois, a Kinder Morgan Canada pipeline spill in Burnaby, B.C., and one spill at a 

TransCanada-operated Keystone Pipeline pump station in North Dakota. Most recently, a 

pipeline failure in the ExxonMobil Pegasus line in Mayflower, Arkansas released a 

significant amount of heavy Alberta crude oil into a suburban residential neighborhood. 

Further information on the Enbridge Michigan, the Kinder Morgan Burnaby, and the 

ExxonMobil Mayflower Arkansas spills and response efforts are provided below and in 

section 7.2.
30

2.1 Recent Spills of Oil Sands Products

2.1.1 Marshall, Michigan Enbridge Spill

The largest dilbit spill, and one of the largest inland oil spills in U.S. history,10 occurred 

on Enbridge’s Line 6B pipeline on July 25, 2010 in Marshall, Michigan (Young, 2012). Line 

6B is a 293-mile section of the Lakehead system, which originates in Edmonton, Alberta. 

The rupture was not discovered for more than 17 hours, and the total release was 

estimated to be 20,082 barrels (bbl)11 of dilbit (NTSB, 2010). The rupture in the line 

measured 6 feet 8.25 inches in length and 5.32 inches at maximum width (NTSB, 2010). Of 

the total oil that spilled, 8,033 bbl reached Talmadge Creek and the Kalamazoo River 

(Enbridge, 2012a).

Enbridge did not initially report that the pipeline was carrying dilbit, and according to 

media outlets, one Enbridge representative denied that the pipeline was carrying oil sands 

products (Lydersen, 2010). Disclosure of this information is not required, and thus it took 

more than a week for federal and local officials to discover they were dealing with a dilbit 

spill (McGowan & Song, 2010).

The U.S. Environmental Protection Agency (EPA) mobilized an Incident Management 

Team in response to the spill that included federal, state, and local agencies. The EPA 

reported that the spill was contained on July 28, 2010, about 80 miles from Lake Michigan, 

and estimated that 27,359 bbl of oil had been recovered as of October 22, 2012; this 

estimate despite the fact that the official spill total was reported to be 20,082 bbl (EPA, 

2012; NTSB, 2012).

Although large-scale cleanup was ongoing at this writing, the estimated response 

costs, including the role of the federal government in cleanup, were about $767 million as 

of October 31, 2011 (NTSB, 2012). Evaluations of air, water, and fish are also continuing

While no impacts on drinking water have been reported and contamination levels of fish 

were not high enough to trigger fish consumption advisories, an assessment of air 

contamination is still pending. (MDCH, 2001-2012).

2.1.2 Romeoville, Illinois Enbridge Spill

Two months after the Kalamazoo River spill in Michigan, another occurred on the 

Enbridge Lakehead System, on Line 6A in Romeoville, Illinois. On September 9, 2010, a 

rupture resulted in a release of about 6,095 bbl of dilbit. A 2.5-inch puncture on the bottom 

of the pipeline was possibly caused by rocks lodged under the structure (although the

official report has not been issued) (Hood, 2010). As with the Michigan spill, the initially 

10 It may in fact be the largest, depending on the final spill volume estimate. A spill near Vienna, Missouri, in December, 

1988 totaled around 20, 500 bbl.

11 1 barrel (bbl) of oil=42 gallons (gal)
31

available information was not specific about the nature of the product in the pipeline; i.e., 

press releases describing the pipeline did not explicitly state that it carried dilbit.

The EPA oversaw the spill response with assistance from state and local agencies. The 

EPA reported the successful completion of its response on October 28, 2010, and 

transferred the cleanup of contaminated groundwater to the Illinois EPA. In total, the EPA 

reported in November 2010 that response efforts resulted in about 20,476 bbl of total oily 

liquids (i.e., oil-water mixture) collected (EPA, 2012). Media outlets report that Enbridge 

cleanup costs for the spill were expected to be $40-$60 million (Huffington Post, 2010).

2.1.3 Burnaby, British Columbia, Kinder Morgan

Three years prior to the Enbridge spills in the U.S., a spill of approximately 1,400 bbl 

of synthetic crude oil occurred in British Columbia. On July 24, 2007, a spill resulted from 

an excavator bucket striking the Westridge Transfer Line in Burnaby, British Columbia, 

during excavation for a new storm sewer line. The pipeline was operated by Kinder 

Morgan Canada and owned by Trans Mountain Pipeline L.P. The pipeline linked the 

Burnaby terminal to the Westridge Dock, where oil could be loaded to tankers (TSB, 

2008a). 

The oil flowed from the ruptured line into Burnaby’s storm sewer systems until it 

reached the Burrard Inlet, ultimately affecting 1,200 meters of shoreline (TSB, 2008a). 

Cleanup took place over a period of months and cost roughly $15 million and resulted in 

the recovery of 1,321 bbl of oil (CBC, 2011).

2.1.4 Keystone Pipeline Spills

In its first two years of operation, the Keystone Pipeline has experienced 35 spills, 14 

of which were in the U.S. (Cornell University, 2012). Although most of these have been 

relatively minor, an accident in North Dakota (described below) resulted in a 500 bbl spill 

of dilbit.

2.1.4.1 Ludden, North Dakota, TransCanada

A failure at a North Dakota pump station resulted in a spill of about 500 bbl dilbit on 

May 7, 2011, causing the entire pipeline system to shut down for nearly one week. Reports 

from the North Dakota Public Service Commission assert that the spill was not due to the 

pipeline itself, but rather resulted from a failed fitting for a valve on the discharge piping 

for the line (Crowl, 2011).

Private contractors and a regional incident management team began cleanup of the 

spill on May 7. All but approximately five bbl of the spilled oil were reported to have been 

contained within the boundaries of the pumping station. Immediately following this spill, 

the U.S. Department of Transportation Pipeline and Hazardous Materials Safety 

Administration (PHMSA) issued a corrective action order requiring operators to replace 

similar fittings on all Keystone pump stations (USDOT PHMSA, 2011).
32

2.1.5 Mayflower, Arkansas, ExxonMobil Pegasus

At this writing, the most recent incident involving an Alberta oil sands product 

occurred on March 29, 2013, when a section of the ExxonMobil Pegasus Pipeline ruptured 

near Mayflower, Arkansas. The 858-mile Pegasus Pipeline carries crude oil from Patoka, IL, 

to Nederland, TX. It links the PADD II area (with inputs from the Mustang, Woodpat, and 

Capline Pipelines) to U.S. Gulf Coast markets (ExxonMobil Pipeline, 2013). The pipeline 

apparently leaked oil from a 22-ft. split for 45 minutes before it was secured. There was 

confusion over the type of oil being carried, as it was initially reported to be a heavy 

Canadian crude oil, but later (April 10) clarified as being Wabasca Heavy, a heavy sour 

diluted bitumen product. Estimates of the amount of product released have varied from 

2,000 to 5,000 bbl. At least 21 homes were evacuated due to elevated volatile organic 

carbon (VOC) readings and because of the amount of oil present in the vicinity (USEPA, 

2013a). 

Cleanup contractors cleaned or removed contaminated storm drains, removed oil 

from residential areas, and used flushing and sorbent material to reduce oiling of a marsh 

area impacted by the spill. After around three weeks, the response transitioned from 

emergency cleanup to a longer-term phase (UPI.com, 2013). Litigation from the incident, 

however, has only recently begun, with both the U.S. Department of Justice and the 

Arkansas attorney general filing separate civil suits against ExxonMobil in federal district 

court in June of 2013.

In July, 2013, ExxonMobil attributed the cause of the Pegasus Pipeline spill to 

manufacturing defects in the original pipeline, calling hook cracks near the seam that split 

open to be the “root cause of the failure.” Metallurgical analysis ruled out corrosion as a 

contributing factor, though the independent report by Hurst Metallurgical Research cited 

other issues, such as low impact toughness and elongation along the seam (Dupre, 2013).

2.1.6 Primrose Operations Area, Canadian Natural Resources LTD

In May 2013, Canadian Natural Resources Limited (CNRL) reported that “bitumen 

emulsion,” a mixture of bitumen and water was leaking at the surface in four different 

areas within its Primrose thermal oil sands project in northeastern Alberta. This 

production area is located within the Cold Lake Air Weapons Range (Healing, 2013). A 

similar incident occurred in the same project area in January of 2009. In the 2013 seepage 

incident, bitumen emulsion was discovered at the surface in one area affecting 

approximately four hectares; this was subsequently upgraded in a CNRL press release to 

four areas and 20.7 hectares. At the end of July, the company also increased its estimate of 

the volume released from an initial 175 barrels to 6,300 barrels of bitumen emulsion. At 

that time, wildlife fatalities included 16 birds, 7 small mammals, and 38 amphibians 

(Canadian Natural Resources LTD, 2013; Dawson, 2013).
33

CNRL attributed the seepage to “mechanical failures of wellbores in the vicinity of the 

impacted locations.” That is, mobilized bitumen was able to make its way to the surface via 

natural cracks and crevices, and then by old vertical wells with insufficient casing and 

cement. The production in the Primrose Operations Areas is a thermal injection process, in 

which high-pressure steam is forced into a deposit and recovered oil pumped to the 

surface. The Alberta Energy Regulator (AER) halted all steaming operations at Primrose on 

July 17, and while AER investigated the root cause of the incidents, CNRL modified its 

production methods and restricted steaming in other areas of potential wellbore failure 

(Dawson, 2013; Canadian Natural Resources LTD, 2013).
34

3 PROJECTIONS OF FUTURE SPILLS

3.1 Does Transport of Oil Sands Products Increase Pipeline Spills?

Although several studies and reports have suggested that pipelines carrying dilbit are 

susceptible to a higher occurrence of spills than those carrying conventional crude oil, due 

to the physical characteristics of dilbit, other investigations suggest that this is not the case. 

Citing PHMSA spill data, a Cornell University report found that between 2007 and 2010 

pipelines transporting dilbit experienced three times more spills per mile in the northern 

Midwest than the national average for conventional crude oil, and attributed the difference 

to the corrosive nature of the oil sands material (Skinner & Sweeney, 2012). The elevated 

corrosivity of oil sands-derived products is, however, a contested issue. Although the 

National Resources Defense Council (NRDC) echoed the findings of the Cornell report by 

stating that dilbit is “more likely to cause corrosion” in pipelines and tankers (NRDC, 2011), 

the conclusion is not supported by other studies indicating that oil sands products are not

significantly more corrosive than conventional petroleum. 

In particular, recent studies characterizing dilbit and oil sands products conducted by 

Heather Dettman of Natural Resources Canada (NRC), and Zhou and Been (commissioned 

by Alberta Innovates) yielded test results leading to the different conclusion. Noting that 

water content is the critical factor in pipeline corrosion, Dettman, and Zhou and Been used 

an analysis of sediment and water content, and other characteristics of oil sands products

to assert that they are not significantly different than comparable heavy crudes and are not 

corrosive enough to be an additional concern to pipeline operators (Dettman, 2012; Zhou

and Been, 2011). For a further discussion of oils sands and pipeline corrosion, refer to 

section 5.5.

3.2 Available Spill Risk Assessments

To determine potential risk of oil spills, public agencies and private consulting firms 

have commissioned assessments on spill potential related to the Keystone, Keystone XL, 

Enbridge Alberta Clipper, and Northern Gateway pipelines. Additional risk assessments for 

the Kinder Morgan Trans Mountain pipeline expansion and the Enbridge Line 9 Reversal in 

Eastern Canada are, respectively, planned and underway.

3.2.1 Pipelines

Based on U.S. Department of Transportation’s statistics, transmission of oil and 

petroleum products via pipeline is the safest mode of bulk transport, measured in terms of 

ratio of accidents per amount transported per year (Table 3-1, Table 3-2) (Furchtgott-Roth, 

2012; Pipeline & Hazardous Materials Safety Administration [PHMSA], 2013).

In compliance with U.S. and Canada governmental requirements to conduct

environmental impact assessments, spill risk data have been made available for the 

TransCanada Keystone, proposed TransCanada Keystone XL, and Enbridge Northern 
35

Gateway pipelines. Assessments are pending for the Kinder Morgan Trans Mountain 

expansion and Enbridge Line 9 Reversal pipelines. Spill risk data are not available for the 

Enbridge Lakehead System (Alberta Clipper and Bakken expansions), Kinder Morgan 

Express, and current Kinder Morgan Trans Mountain pipelines. As U.S. and Canadian 

reporting and assessment requirements differ and accessibility of documents vary, the 

amount, source, and presentation of data on spill risk are not consistent across these 

studies and make direct comparisons difficult. 

Table 3-1: Incident Rates Onshore Transmission Pipelines vs. Road and Railway (2005–2009)

Comparative Statistics for Incident Rates Onshore Transmission

Pipelines vs. Road and Railway

(2005-2009)

Mode

Billions Ton 

Miles of 

Shipment

Average 

Hazmat 

Incidents per 

Year

Average Hazmat 

Incidents per 

Billion Ton Mile

Road 23 14,963 650.6

Railway 35.1 718 20.5

Hazardous Liquid Pipeline (Onshore) 584.1 354 0.61

Gas Transmission Pipeline (Onshore) 338.5 300 0.89

Table 3-2: National Pipeline Systems –Reported Incidents Summary Statistics: 1993−2012

Year Number Fatalities Injuries 

Property 

Damage as 

Reported

($ million)

Gross 

Barrels 

Spilled

Net 

Barrels 

Lost

% of 

Volume 

Recovery

1993 445 17 111 $67.3 116,802 57,559 51%

1994 467 22 120 $160.6 164,387 114,002 31%

1995 349 21 64 $53.4 110,237 53,113 52%

1996 381 53 127 $114.5 160,316 100,949 37%

1997 346 10 77 $79.8 195,549 103,129 47%

1998 389 21 81 $126.9 149,500 60,791 59%

1999 339 22 108 $130.1 167,230 104,487 38%

2000 380 38 81 $191.8 108,652 56,953 48%

2001 341 7 61 $63.1 98,348 77,456 21%

2002 644 12 49 $102.1 97,255 77,953 20%

2003 673 12 71 $139.0 81,308 50,889 37%

2004 673 23 60 $271.8 89,311 69,003 23%

2005 721 14 48 $1,246.8 138,094 46,246 67%

2006 642 21 36 $151.1 137,693 53,905 61%
36

Year Number Fatalities Injuries 

Property 

Damage as 

Reported

($ million)

Gross 

Barrels 

Spilled

Net 

Barrels 

Lost

% of 

Volume 

Recovery

2007 615 15 50 $154.9 94,981 68,941 27%

2008 662 8 57 $565.9 102,076 69,510 32%

2009 627 13 64 $179.0 55,014 32,307 41%

2010 590 22 109 $1,465.3 174,931 123,420 29%

2011 595 14 60 $365.3 139,017 108,140 22%

2012 569 12 56 $188.4 54,061 32,401 40%

3.2.2 Rail

Risk assessments for rail transport are not conducted according to the specifics of the 

material being transported; therefore, it is not possible to isolate dilbit as a discrete factor 

in contributing to spill risk. However, an EPA report does provide rail-specific data of on 

spills of all types of oil in U.S. inland waterways. Between 1980 and 2003, 265 spills were 

attributed to rail accidents, which accounted for 0.05 percent of the total number of spills 

over that timeframe. The average volume per spill was 8,185 gallons (Etkin, 2006). 

Further discussion on rail transport and regulation are provided in sections 4.2 and 8.3.3.2.

3.2.3 Waterways and Terminals

With respect to spill risks involving coastal terminals and waterways, Enbridge has 

published spill risk assessments for their proposed pipeline to the Kitimat Terminal. A 

separate risk assessment was recently completed for the Aleutian Islands, focusing on the 

risks related to increased vessel traffic through regional passages. These are discussed 

below. Risk assessments for other terminals expected to handle oil sands products will not 

take place until upgrades to facilities are underway and regulations require assessments to 

take place.

3.3 Keystone XL Pipeline

The U.S. State Department has released two Environmental Impact Statements (EIS) 

for the Keystone XL pipeline. The most recent of these was released in March, 2013, and

considered an alternative routing for the pipeline through Nebraska.

The 2013 draft EIS of Keystone XL summarized pipeline spill releases reported by 

volume. Based on historical spill data from PHMSA, the State Department projected that 

for all spills along all pipeline components, 79 percent will be less than 50 bbl, 17 percent

will be 50-1,000 bbl, and 4 percent will be 1,000-20,000 bbl. Translating the risk 

projections into accidents per length of pipeline over time estimated 0.00313 incidents per 

mile-year—of which 21 percent would exceed 50 bbl. The final EIS noted that an 

undetected leak along a buried section of the pipeline could saturate soil with the potential 
37

for the material spilled to reach groundwater resources. The Final EIS also provided 

estimates of pipeline mileage that could potentially affect water bodies. Narrowing the 

analysis to water bodies in Montana, South Dakota, and Nebraska, it was asserted that that 

there were about 355 miles, 129 miles, and 278 miles of pipeline in each state, respectively,

subject to spill risk greater than 50 bbl that could potentially affect water bodies (U.S. 

Department of State, 2013). 

The first EIS for the Keystone XL Pipeline provided estimates for “significant spills,” or 

those predicted to exceed 50 bbl. Drawing on historical spills from the PHMSA database, 

the estimated projection for significant spills was 1.18 spills per year (.0007 per mile over 

1,682 miles). This would be equivalent to nearly 59 spills greater than 50 bbl over the 50-

year design life of the pipeline.

The EIS indicated that the maximum potential spill volume was 66,666 bbl, which, due 

to topography, was a risk along less than 1.7 miles of the proposed route. Taking into 

account factors such as shutdown time, structural failure, flow rate, and line drainage 

volumes: for about 50 percent of the proposed pipeline route, the maximum spill volume 

was estimated to be about 16,000 bbl, which would result only from a “complete structural 

failure of the pipeline” (U.S. Department of State, 2011). The EIS also asserted that spill 

volumes would be much lower at river crossings because main line valves (MLVs) occurred

on either side of each river crossing (U.S. Department of State, 2011).

Two additional assessments of the Keystone XL pipeline provide different figures. An 

assessment carried out by TransCanada contractor DNV Consulting, found the likelihood of 

significant spills (i.e., greater than 50 bbl) to be .21 (.00013 per mile) or about 11 spills 

over 50 years. John Stansbury of the University of Nebraska has argued that these figures 

are “highly questionable” because the firm failed to take into account the historical PHMSA 

spill data that comprised 23 percent of historical pipeline data (Stansbury, 2011). 

Inclusion of the PHMSA data and assuming the increased acidity and sulfur content of oil 

sands products would increase corrosiveness and abrasiveness (see discussions elsewhere 

in this document regarding this issue), Stansbury’s risk prediction for Keystone XL was

1.83 (.00109 per mile) or 91 significant spills over 50 years (Stansbury, 2011). However, 

with empirical tests for corrosivity indicating that dilbit is not significantly different from 

other Alberta petroleum products, the Stansbury risk projection may be overestimated. 

Dr. Stansbury also provided worst-case spill scenarios for major Keystone XL river 

crossings and the Sandhills region of Nebraska. At the Missouri River Crossing, his worstcase spill prediction was 122,867 bbl; for the Yellowstone River, the worst-case prediction 

was 165,416 bbl; and at the Platte River crossing, the worst-case prediction is 140,950 bbl 

(Stansbury, 2011).

A DNV Energy analysis carried out for TransCanada provided estimates for spills 

greater than 50 bbl on the Keystone pipeline. Utilizing data specifically for spills of diluted 

bitumen, DNV stated in a discussion of uncertainty that their estimates assumed failure 

causes were identical to crude oil (DNV Energy, 2011). The DNV estimates were 0.094 and 
38

0.151 spills per year, respectively, for the mainline and the mainline plus the Cushing 

extension (DNV Energy, 2011). Over a fifty-year period, this equated to 4.70 and 7.55 spills 

respectively.

For worst-case spills, Dr. Stansbury used Keystone figures to support his analysis of 

Keystone XL. He asserted that TransCanada estimated worst case spills for the Keystone 

pipeline (at Hardisty Pumping Station) to be 41,504 bbl, while Stansbury’s estimate was 

closer to 88,000 bbl (Stansbury, 2011). The principal source of the substantial difference 

between the two estimates was the assumed time to shut in the pipeline following an 

accident: 19 minutes for TransCanada, and two hours for Stansbury (Stansbury, 2011).

3.4 Northern Gateway Pipeline

Enbridge provided data on spill risks for their Northern Gateway pipeline, the Kitimat 

(B.C.) Terminal, and associated waterways in a 2011 General Oil Spill Response Plan 

(Enbridge, 2011). The estimated spill frequency data in the report was provided in spill 

return years (number of years per spill). Converting these figures to yearly spill 

likelihoods, the company predicted 0.036 spills per year greater than 62.8 bbl on the 

pipeline in the region between Alberta and Kitimat. The maximum spill volume along the 

pipeline was predicted to be 49,060 bbl at kilometer point (KP) 165 near Mayerthorpe. 

The assessment also stated that the pipeline was designed to limit spill volumes at 

watercourse crossings to less than 12,579 bbl. For spills at the Kitimat Terminal involving 

a tanker at berth, Enbridge projected 0.002 spills greater than 62.8 bbl per year. A 

separate, third-party assessment carried out by University of British Columbia engineering 

professors estimated the spill rate per year at 0.014 (Gunn et al, 2012). The maximum spill 

volume at the terminal was predicted to be 10,063 bbl. For waterway spills associated 

with tanker traffic, there would be an estimated 0.003 spills per year of any volume and 

0.002 spills per year greater than 31,449 bbl. The maximum spill volume for a waterway 

spill was estimated to be 226,433 bbl.

3.5 Unimak Pass

An assessment of worst case spills in the Aleutian Islands, far from the regional focus 

of this report, is nonetheless relevant, given the likelihood that oil sands products will be 

shipped for export to Asia via great circle routes through that region, and specifically, 

through Unimak Pass. Data analyzed for the Aleutian risk assessment originated with the 

National Fish & Wildlife Foundation, U.S. Coast Guard, and State of Alaska Department of 

Environmental Conservation. Nuka Research oversaw the resultant multi-phase risk 

assessment of maritime transportation in the Bering Sea and the Aleutian Archipelago. 

Providing baseline and future accident estimate predictions for all vessels (8.67 for 

2008/2009 and 9.61 for 2034), a summary report of the assessment estimated that 

collisions with crude oil tankers along this route could result in a spill of 428,080 bbl

(Aleutian Islands Risk Assessment Management Team, 2011).
39

4 TRANSPORTATION METHODS

As stated in section 1.4, pipelines, rail, barges and tankers are the primary modes of 

transporting crude oil products from source to markets in North America. Canada 

produced roughly 1.2 billion barrels in 2012 (approximately 3.5 mbl/d), 55 percent of 

which were oil sands products (upgraded bitumen and non-upgraded bitumen) (CNEB, 

2012). As of 2011, 65 percent of Canadian crude oil production was destined for the U.S 

(CNEB, 2012; EIA, 2012). Currently, the most widely used mode of exporting Canadian 

crude oil to the U.S. is the use of pipelines. Canada exported 89 percent of its crude oil via 

pipelines, 10.8 percent via marine transportation and 0.2 percent via rail (CNEB, 2012). 

However, due to environmental and political challenges to pipeline expansion, the use of 

rail as an alternate mode of transport is rapidly growing (EIA, 2013; CNEB, 2012). From 

2007 to 2011, the use of pipelines grew by only 5.3 percent yearly and use of marine

(tankers and barges) shrank by 2.4 percent yearly; meanwhile, use of rail has increased by 

over 7000 percent yearly (EIA, 2013; CNEB, 2012). The apparently phenomenal growth in 

use of rail stems from the fact that almost no crude oil was transported via rail prior to 

2009 (EIA, 2013; CNEB, 2012). 

The U.S. market accounts for 97 percent of Canadian crude oil export (CNEB, 2012). 

In 2012, Canada’s crude oil export to the U.S. included conventional light (API < 30), 

conventional medium (25 < API < 30), conventional heavy (API < 25), synthetic (upgraded 

bitumen or upgraded heavy crude oil of any API), and blended bitumen (bitumen blended 

with light hydrocarbons and/or synthetic crude oil) (CNEB, 2012). As of the 3rd quarter of 

2012, oil sands products were the most prevalent type of crude oil product exported to the 

U.S. (31 percent), followed by conventional heavy (24 percent), synthetic (24 percent), 

conventional light (18 percent) and conventional medium (3 percent) (CNEB, 2012). The

U.S. consumes 99 percent of the Canadian oil sands crude products destined for export 

(CNEB, 2012).

Major policy and research gaps exist related to transportation of oil sands products 

via all means of conveyance. These should be addressed to provide policy makers and 

governmental organizations a sound and informed basis for evaluating the environmental, 

social and economic tradeoffs related to integration of oil sands products into the global 

energy economy. Sections 8.8 and 9 provide an overview of some of the identified gaps in 

both policy and research.

4.1 Pipelines

Pipelines are the primary mode of transportation for oil products in North America. 

Approximately 71 percent of crude oil and petroleum products (including crude oil and 

post-refining products) are shipped via pipelines on the ton-mile basis (mass in tons * 

distance in miles) (Bureau of Transportation Statistics [BTS], 2012). Tanker and barge 

traffic accounts for roughly 23 percent of oil shipments, and rail about 3 percent (Table 
40

4-1) (BTS, 2012). By narrowing the focus to the crude oil products, including all types of 

crude oil, the reliance on pipeline transport becomes even more evident: in 2009, roughly 

80 percent of all crude oil transport in ton-miles in North America was via pipelines, while 

tankers and barges accounted for 19 percent and rail 0.3 percent respectively (Table 4-1) 

(BTS, 2012). 

Table 4-1: Crude Oil and Petroleum Products Transported in the US by Mode

Crude Oil and Petroleum Products Transported in the United States by Mode 

(billions)

2008 2009

TonneKilometersTonMiles % TonneKilometersTonMiles % 

Crude oil, total 543.1 372.0 100.0% 490.6 336.0 100.0%

Pipelines 447.2 306.3 82.3% 391.6 268.2 79.8%

Water carriers 92.3 63.2 17.0% 95.0 65.1 19.4%

Motor carriers 2.5 1.7 0.5% 2.5 1.7 0.5%

Railroads 1.0 0.7 0.2% 1.5 1.0 0.3%

Refined petroleum 

products, total 709.4 485.9 100.0% 692.2 474.1 100.0%

Pipelines 437.1 299.4 61.6% 438.3 300.2 63.3%

Water carriers 191.0 130.8 26.9% 177.7 121.7 25.7%

Motor carriers 48.8 33.4 6.9% 47.0 32.2 6.8%

Railroads 32.6 22.3 4.6% 29.1 19.9 4.2%

Combined crude 

and petroleum 

products, total

1,252.5 857.9 100.0% 1,182.7 810.1 100.0%

Pipelines 884.3 605.7 70.6% 829.8 568.4 70.2%

Water carriers 283.2 194.0 22.6% 272.7 186.8 23.1%

Motor carriers 51.2 35.1 4.1% 49.5 33.9 4.2%

Railroads 33.6 23.0 2.7% 30.5 20.9 2.6%

It is important to distinguish among pipeline types used by the industry, as they are 

distinctly different in their requirements and characteristics—and hence, their spill risk. 

The three major categories of pipeline systems that support transfer of oil from its source 

to destination are gathering; crude oil; and refined products; with sizes ranging from 2 

inches to 42 inches in diameter (Figure 4-1) (BTS, 2012). The U.S. has a network of 

175,000 miles of these pipelines for the purpose of onshore and offshore transmission of 

crude oil and petroleum products (BTS, 2012). Gathering pipeline systems gather crude oil 

from production wells. Crude oil pipeline systems transport crude oil from the gathering 
41

systems to refineries. Refined products pipeline systems transport refined products such as 

gasoline, kerosene and many industrial feedstock petrochemicals from refineries to the end 

user or to storage and distribution terminals (BTS, 2012). 

Figure 4-1: US DOT, PHMSA’s Petroleum Pipeline Systems (Credit: U.S. Department of Transportation, 2012)

4.1.1 Networks of Crude Pipelines in North America

As stated in section 1.4.1, four major networks of crude pipelines in North America 

carry crude products from the source (wells and mines) to the destination (refineries and 

offshore terminals for tanker shipment) with an average capacity of 3.5 mbl/d (CAPP, 

2012; CNEB, 2009). 

Canadian heavy-crude prices have declined relative to comparable U.S. and 

international benchmarks due to the shortage of transport capacity to move the increased 

production to market (Olson & van Loon, 2013). According to Bloomberg News, the price 

of Western Canada Select, a blend refined from oil sands bitumen, had fallen over 20

percent over a six-month period in 2012-2013 amid uncertainty over approvals for 
42

Keystone XL, Enbridge’s Northern Gateway and Kinder Morgan Energy Partners LP 

(KMP)’s TransMountain pipelines (Olson & van Loon, 2013). 

4.1.1.1 Enbridge Mainline Pipeline System

The Enbridge pipeline system delivers crude oil and other refined products from 

western Canada, Montana, and North Dakota to markets in western Canada, the U.S. PADD 

II, and Ontario (CAPP, 2012; CNEB, 2009). The system connects to a number of regional 

pipelines in the U.S. PADD II region, such as the Minnesota Pipeline at Clearbrook, MN and 

Spearhead South at Flanagan, IL (CAPP, 2012; CNEB, 2009). The Enbridge system has the 

capacity of 2.3 mbl/d (CAPP, 2012; CNEB, 2009; CNEB, 2006). 

The Enbridge network is currently being expanded through upgrades to two of its 

main pipelines, Alberta Clipper and Southern Access (CAPP, 2012; CNEB, 2009). By 2014, 

when the expansion projects are completed, the Alberta Clipper will add 0.12 mbl/d of 

capacity and the Southern Access will add 0.16 mbl/d capacity (CAPP, 2012; CNEB, 2009; 

CNEB, 2006). 

4.1.1.2 Kinder Morgan Express and Trans Mountain Pipeline Systems

Kinder Morgan Canada, Inc., is the parent company of both Kinder Morgan and Trans 

Mountain Pipelines (CAPP, 2012; CNEB, 2009). The Trans Mountain system originates in 

Edmonton, Alberta and transports crude oil and petroleum products to delivery points in 

British Columbia, including the Westridge Dock for offshore exports, to final destinations 

that include the U.S. PADD V (primarily CA and WA) and Asia (CAPP, 2012; CNEB, 2009; 

CNEB, 2006). 

The system also includes the Express Pipeline system, which is comprised of the 

Express Pipeline and the Platte Pipeline (CAPP, 2012; CNEB, 2009). This system connects 

Canadian and U.S. crude oil producers to refineries in the U.S. PADD II and PADD IV (CAPP, 

2012; CNEB, 2009). The Express Pipeline originates at Hardisty, Alberta, and ends at the 

Casper, WY facilities on the Platte Pipeline with a capacity of 0.280 mbl/d (CAPP, 2012; 

CNEB, 2009; CNEB, 2006). The Platte Pipeline runs from Casper, WY to refineries and 

interconnecting pipelines in Wood River, IL with the capacity of 0.15 mbl/d (CAPP, 2012; 

CNEB, 2009). 

4.1.1.3 TransCanada Keystone Pipeline System

The existing Keystone pipeline system runs from Hardisty, Alberta, to terminals in 

Wood River and Patoka, IL (CAPP, 2012; CNEB, 2009). The latest extension of the Keystone 

pipeline is the Cushing Extension, which runs from Steele City, NE to Cushing, OK (CAPP, 

2012; CNEB, 2009). The system has a capacity of 0.591 mbl/d to either Wood River or 

Cushing depending on market requirements (i.e., flow is bidirectional) (CAPP, 2012; CNEB, 

2009; CNEB, 2006). 
43

TransCanada’s future expansion plan includes the Keystone XL pipeline. The purpose 

of this pipeline would be to transfer oil sands products from Alberta to refineries on the 

Gulf Coast (PADD III), which would represent a gateway to international markets. The 

initial routing plan faced fierce objections from a variety of stakeholders, including several

state governments and environmental groups (Avok, 2011). A new revised route was

proposed to address the environmental concerns related to the original routing through 

the state of Nebraska. This new route proposal resulted in the Nebraska governor 

approving the passage of pipeline through his state (Gardner & Quinn, 2013). On March 1, 

2013, the U.S. State Department issued a revised environmental impact statement for the 

Keystone XL pipeline. The statement “made no recommendation about whether the 

project should be built, (but) it presented no conclusive environmental reason that it 

should not be” (Broder, 2013). Thus, the report facilitated the potential final approval by 

the U.S. government (Broder, 2013). At this writing, the fate of the proposal rests with the 

U.S. President. If approved, TransCanada planned to begin the construction of the pipeline 

in 2013, with a targeted in-service date of 2015 (TransCanada; Gardner & Quinn, 2013). 

The Keystone XL would originate at Hardisty, Alberta and terminate at Steele City, NE 

(TransCanada). The proposed expansion would result in a transfer capacity of 0.83 mbl/d, 

with its primary function to transport synthetic crude oil and dilbit from the Athabasca oil 

sands region to multiple destinations in the U.S. PADD II, III and IV (CAPP, 2012; CNEB, 

2006). 

4.1.2 Regional Crude Pipelines in the U.S.

Table 4-2 lists all major crude pipelines connecting Canadian sources to various 

regions of the U.S. The table is divided into multiple U.S. PADD regions (CAPP, 2012; CNEB, 

2009; CNEB, 2006). 

Table 4-2: Major Crude Pipelines Connecting Canadian Sources to the U.S. Destinations

Summary of Crude Oil Pipelines to the U.S. East Coast - U.S. DOE PADD I

Pipeline Originating 

Point Destination Status Capacity(mbl/d)

Enbridge Line 9 Sarnia, ON Montréal, QC Operating 0.24

Enbridge Line 9 Reversal Montréal, QC Sarnia, ON Changed Direction –

1999 0.24

Portland-Montreal Montréal, QC Portland, ME Operating 0.60

TransCanada East Coast 

Pipeline Project Montréal, QC Saint John, NB Proposed – 2015 0.63
44

Summary of Crude Oil Pipelines to the U.S. Midwest & Rocky Mountain - U.S. DOE 

PADD II & PADD IV 

Pipeline Originating 

Point Destination Status Capacity(mbl/d)

Minnesota Pipeline Clearbrook, MN Minnesota 

refineries Operating 0.47

Enbridge Mainline Superior, WI Multiple delivery 

points Operating 1.56

Spearhead North 

Expansion Flanagan, IL Spearhead North Chicago, IL Proposed – 2014 0.10

Enbridge Spearhead South Flanagan, 

IL Cushing, OK Operating 0.19

Enbridge Flanagan South Flanagan, IL Cushing, OK Proposed – 2014 0.59

Enbridge Mustang Lockport, IL Patoka, IL Operating 0.10

Kinder Morgan ExpressPlatte Guernsey, WY Wood River, IL Operating 0.15

Trans Canada Keystone 

to Patoka or Wood River Hardisty, AB Patoka, IL Operating 0.59

Trans Canada Keystone 

to Cushing Steele City, NE Cushing, OK Operating 0.59

Summary of Crude Oil Pipelines to the U.S. Gulf Coast - U.S. DOE PADD III

Pipeline Originating 

Point Destination Status Capacity(mbl/d)

ExxonMobil Pegasus Patoka, IL Nederland, TX Operating 0.10

Seaway Reversal Phase 1 Cushing, OK Freeport, TX Operating – May 2012 0.15

Seaway Reversal Phase 2 Cushing, OK Freeport, TX Proposed – Early 2013 0.25

Seaway Twin Line Cushing, OK Freeport, TX Proposed – Mid 2014 0.45

TransCanada Gulf Coast Cushing, OK Nederland, TX Proposed – Mid 2014 0.55

Summary of Crude Oil Pipelines to the West Coast - U.S. DOE PADD V

Pipeline Originating 

Point Destination Status Capacity(mbl/d)

Kinder Morgan Trans 

Mountain

Edmonton, AB Burnaby, BC Operating 0.30

Kinder Morgan Trans 

Mountain Expansion

Edmonton, AB Burnaby, BC Proposed – 2017 0.45

Enbridge Northern 

Gateway Bruderheim, AB Kitimat, BC Proposed – 2017 0.53
45

4.1.3 Diluent Pipelines

Table 4-3 summarizes the proposed pipelines for transport of diluent in opposite 

direction to the locations where oil sands upgrading occurs. These pipelines would

address the potential demand by western Canadian oil sands producers for additional 

diluent supply needed to transport growing volumes of bitumen-derived products (CAPP, 

2012; CNEB, 2009; CNEB, 2006). 

Table 4-3: Summary of Major Diluent Pipelines

Summary of Diluent Pipelines

Pipeline Originating 

Point Destination Status Capacity(mbl/d)

Enbridge Southern 

Lights Flanagan, IL Edmonton, AB Operating 0.18

Enbridge Northern 

Gateway Kitimat, BC Edmonton, AB Proposed – 2017 0.19

Kinder Morgan Cochin 

Conversion

Kankakee County, 

IL

Fort 

Saskatchewan, AB

Open Season – Ends May 

2012 0.08

Portland-Montreal 

Bitumen Expansion Montréal, QC Portland, ME Proposed – 2017

4.2 Rail Transportation

The rapid increase in production of crude products in North America, and the costly 

and lengthy process of obtaining permits for new pipelines, have transformed rail into the 

current transport mode of choice for crude oil products, especially at new crude production 

sites (Black, 2013). The number of crude oil-carrying rail cars tripled to more than 

200,000 units between 2011 and 2012, and is expected to continue to grow in the

foreseeable future (Black, 2013). Furthermore, an analysis conducted by the U.S. 

Department of State indicated that with modest expansion and upgrades to the existing 

infrastructure, railroad networks in the U.S. could handle all new oil produced in western 

Canada through 2030 (Efstathiou, 2012; U.S. Department of State [DOS], 2013). 

The major players in the transportation of crude products via rail in North America 

are Canadian National Rail (CN), Canadian Pacific Rail (CPR) and Burlington Northern 

Santa Fe (BNSF). These companies, along with other rail companies and major oil car 

manufacturers in North America, have projected continuous growth in the sector for the 

foreseeable future, due to the slow process of granting permits for new pipelines 

(Vanderklippe, 2013). It remains to be seen whether the recent rail accident at LacMégantic in Quebec affects this trend in growth.
46

Since trains classify commodities by their weight (typically in tons or carloads) and 

pipelines move oil products by the barrels/day, direct comparison of the two modes of 

transport is difficult (Furchtgott-Roth, 2012; Vanderklippe, 2013). Nevertheless, studies 

have been conducted to do just that: compare the two modes of transporting oil products

(Furchtgott-Roth, 2012; Vanderklippe, 2013). A report by the Manhattan Institute 

aggregated data from U.S. Department of Transportation and examined risks associated 

with the transport of crude oil and petroleum products via pipelines, rail, trucks, and ships. 

The study determined that the average hazardous materials incident per billon-ton mile 

rates were 0.61 spills for pipelines; 20.5 for rail; and 650.6 for road (trucks and etc.) 

(Furchtgott-Roth, 2012). Comparing pipelines vs. rail yields a spill rate 34 times higher for 

rail (Furchtgott-Roth, 2012). As might be anticipated, the American Association of 

Railroads (AAR) disputed that analysis and conclusion. According to an AAR’s internal 

study, there was a much smaller spill rate of 2.6 times the pipeline rate (Association of 

American Railroads [AAR], 2013). The AAR analysis also determined that on average, 

trains leak smaller amounts than pipelines (AAR, 2013). The discrepancies and differences 

between the two analyses have not been independently assessed. The AAR website 

maintains that “railways spill less of their hazardous liquid product than do pipelines, nine

percent less per billion barrel miles over the 20-year period 1990-2009, and 35 percent

less over the 2002-2009 period” (AAR, 2013). 

The Railway Association of Canada (RAC) has stated that, unlike pipelines, trains are 

able to transport undiluted oil sands crude (bitumen) (Vanderklippe, 2013). The naturally 

high viscosity of the unmixed bitumen raw product has even been touted as a cleanup 

advantage in the event of a derailment and spill: Michael Bourque, president of the RAC, 

stated in an interview with the Globe and Mail, “...It’s like molasses in January coming out. 

So you’re not going to have a huge problem.” (Vanderklippe, 2013).

Aside from the apparently conflicting statistics presented by the rail and pipeline 

industries, the reality is that both means of transporting crude oil have experienced 

accidental spills in recent years. For example, CN trains leaked roughly 4,400 barrels of 

Bunker C in Lake Wabamun, Alberta, in 2005; and a derailment and explosion near 

Rockford, IL, released 7,700 barrels in 2009 (Vanderklippe, 2013). As we have discussed 

previously in Section 2, pipelines have also been subject to spills. 

Rail is and will be used to ship oil sands products from Alberta to U.S. markets. 

According to TransCanada’s president, Alex Pourbaix, even if all of the proposed pipeline

projects were delayed, oil-sands development could continue because the option of crude 

exports by rail connecting to refineries and ports offers a viable alternative—even though 

shipping oil by rail is about two to three times more costly than by pipeline (Olson & van 

Loon, 2013). 
47

4.3 Marine Shipment

Barge and tanker shipment of crude and petroleum products within North America 

and to Asia and other consumer markets is expected to grow dramatically (International 

Energy Agency, 2012). It is anticipated that tanker traffic will show the greatest growth in 

Puget Sound, the Gulf of Mexico, and Maine, if the proposed Enbridge Gateway (West Cost), 

TransCanada’s Keystone XL (Gulf Coast) and Kinder Morgan Trans Mountain Expansion of 

Portland-Montreal’s Bitumen Expansion (East Coast) are approved (CAPP, 2012). 

Due to the limited availability of data for other regions, the remainder of this section 

will focus on increased vessel traffic in Pacific Northwest, especially in Puget Sound, Strait

of Juan de Fuca and Unimak pass and Aleutian Islands.

4.3.1 Puget Sound Waters – British Columbia to Washington

Increased traffic in the Puget Sound region would be primarily due to barges that 

carry crude oil products from British Columbia to refineries in Washington State, with most 

barges transiting from Vancouver, BC, to refineries in Cherry Point (northern Puget Sound) 

and Tacoma (south-central Puget Sound) (Jensen & Pilkey-Jarvis, 2012). 

4.3.2 Strait of Juan de Fuca – British Columbia to Western U.S. States and Asia

The Pacific Northwest also serves as a shipping gateway for crude oil export from the 

ports of Vancouver, BC, Grays Harbor, WA, and Tacoma, WA, to markets in California and 

across the Pacific region (primarily Asia) through Puget Sound and Strait of Juan de Fuca 

(Figure 4-2) (Jensen & Pilkey-Jarvis, 2012). This potential increase in barge and tanker 

traffic in the Strait has caused multiple stakeholders in the region, including the Makah 

Tribe and Puget Sound Partnership, to commission a risk study by George Washington 

University. The purpose of this study, called the Vessel Traffic Risk Assessment (VTRA), is 

to develop a geographic profile for oil spill risk simulation using 2010 vessel traffic data 

(Hass, 2013; van Dorp, 2013). The report will analyze geographic profiles of 2005 and 

2010 oil spills by vessel type and location, summarized in Table 4-4. It will consider the 

increased traffic due to Gateway and Kinder Morgan’s pipeline proposals to ship Canadian 

crude oil products from British Columbia to Asian markets, as well as the increased reshipment inside Puget Sound waters by barges (Hass, 2013). The study’s initial report is 

due in August 2013.
48

Table 4-4: Scope of the VTRA Study Commissioned by Makah Tribe and Puget Sound

LOCATION VESSEL TYPE

Cherry Point Area Tug without Barge

Puget Sound South Tug ATB's or ITB's

Strait of Juan de Fuca East Tug Pushing Ahead

Strait of Juan de Fuca West Container

Puget Sound North Tanker

Saddle Bag Area Bulk carrier

Rosario Strait Freighter

Haro Strait \ Boundary Pass Passenger vessel

Guemes Channel Service vessel

Public vessel

Fishing Vessel

Tug Towing Astern

Recreational Vessel

The Government of British Columbia and environmental organizations, such as 

Natural Resources Defense Council, Pembina Institute and Living Oceans Society, also

studied the increased social, economic, and environmental risks resulting from vessel 

traffic growth in Puget Sound and the Strait of Juan de Fuca waters—especially the rapid 

growth in tanker traffic (Government of British Columbia [Gov. BC], 2012; Swift, Lemphers

et al., 2011). The report categorized risks into four major areas that included: 

• “Compromising the lifestyles of First Nations who depend on the region’s lands and

waters for their livelihoods, culture, and health;

• “Threatening the economic well-being of the communities of British Columbia that

depend on fisheries and forests;

• “Potential devastation from a major oil spill from the pipeline or an oil supertanker,

which could destroy economically important salmon habitat, as well as the habitat

of Spirit Bears and grizzlies, and whales, orcas, and other marine life that depend on

these rich coastal waters;

• “Harm from an oil spill to the Great Bear Rainforest that the province and First

Nations have worked hard to protect from unsustainable forestry practices and to

shift to a conservation-based economy” (Swift, Lemphers et al., 2011).

Figure 4-2 is a graphic of the response processes applicable to British Columbia in the 

event of a major marine spill. The flow of these processes was developed to address some 

of the concerns raised during that government’s assessment of rapid growth in tanker 

traffic in Strait of Juan de Fuca (Government of British Columbia, 2012). 
49

Figure 4-2: Map of Crude Oil Transport in Washington State (Credit: WA Department of Ecology, 2012) 

4.3.3 Unimak Pass and the Aleutian Islands – British Columbia to Asia

If the Enbridge Northern Gateway pipeline to Kitimat, BC, is approved, there would be 

a large increase in tanker traffic from Kitimat to Asian markets through the Aleutian 

Islands (Hass, 2013). This increase in tanker traffic, coupled with dramatic growth in 

overall trans-Pacific vessel traffic due to advancement of trade relations across Asia and 

North America, would amplify the risk of accidents and spills in waters off the coast of the 

Aleutian Islands (Transportation Research Board of the National Academies [TRB], 2009). 

This is due to the geometry and the geography of the “Great Circle Routes” that ships 

navigate between North America and Asia on the sphere of the globe: somewhat counterintuitively, the shortest distance between ports is a route that routinely takes a ship north 

through the Aleutian Islands into the Bering Sea, often through the major opening, Unimak 

Pass. The Aleutian Islands’ abundant natural resources are unique to that region and a 

major source of that region’s economic vitality (TRB, 2009). As the 2004 Selendang Ayu

grounding, breakup, and oil spill demonstrated, any accidents related to this vessel traffic, 

whether they involve tanker or cargo ships, could result in oil spills with serious
50

environmental, social, economic, and logistical consequences. One consequence of the 

Selendang Ayu spill was that the owner of the ship was required to pay $3 million to fund a 

risk assessment to define the risks and generate recommendations for mitigation. The U.S. 

Coast Guard (USCG) commissioned the Transportation Research Board (TRB) within the 

U.S. National Academies to conduct the study (TRB, 2009). The final report was titled, 

“Risk of Vessel Accidents and Spills in the Aleutian Islands: Designing a Comprehensive 

Risk Assessment” and was published in 2009.

The primary recommendation of the report was that comprehensive long-term study 

of vessel accident risks around the Aleutian Islands be commissioned, but it also offered 

USCG some interim risk mitigation recommendations: 

• “USCG to take appropriate action to expand the Automatic Identification System

(AIS) vessel tracking network along the Aleutian chain and covering the southern

North Pacific Great Circle Route;

• “USCG to investigate the possible structure and costs of a Vessel Traffic Information

System within and near Unimak Pass and Dutch Harbor (TRB, 2009).”

Data gathered during the interim period will contribute to the more comprehensive 

risk assessment study; information about this ongoing work can be found at: 

http://www.aleutiansriskassessment.com. 
51

5 PROPERTIES, FATE, AND BEHAVIOR OF OIL SANDS PRODUCTS

5.1 Definition of Terms

Specific gravity and API (American Petroleum Institute) gravity are both measures of 

density relative to water. Although specific gravity is a more common measurement in the 

broader scientific community, API gravity is standard when comparing the densities of 

petroleum products.

• Specific Gravity in calculated based directly on a material’s density and uses pure

water as the benchmark, assigning it a specific gravity of 1.0. That is, anything with a

specific gravity greater than 1.0 is denser than water and will sink; while anything

with a specific gravity less than 1.0 will float.

• API Gravity also uses pure water as the benchmark, but assigns it a value of 10.0.

The other key difference between the two measurements is that API gravity is an

inverse measure of relative density compared to water, so as a substance’s API value

increases, it reflects a lower density relative to water. Thus, a material with an API

gravity greater than 10.0 will float on pure water; and anything with an API gravity

of less than 10.0 will sink. The API gravity for saltwater is around 6, so anything

with API gravity greater than 6.0 will float in saltwater and anything with an API

less than 6.0 will sink in saltwater. API is expressed mathematically as: °API =

(141.5/SG) – 131.5, where SG = specific gravity.

•

•

Total Acid Number (TAN) measures the composition of acids in a crude oil, which

can gauge its potential for corrosion of pipes or other equipment during

transportation or refining. TAN value is measured as the number of milligrams (mg)

of potassium hydroxide (KOH) needed to neutralize the acids in one gram of oil.

Crude oils with a TAN greater than 0.5 are considered to be potentially corrosive

due to the presence of naphthenic acids (Ramseur et al, 2012). However, while

increased TAN values do increase the potential for corrosion, according to some

experts, water content in the oil may be the key factor that leads to corrosion in a

pipeline (Dettman, 2012).

Miscible & Non-Miscible vs. Soluble & Non-Soluble refers to the ability of one

substance (the solute) to mix completely with another substance (the solvent) and

become homogeneous. Miscible refers to the mixing of two liquids, whereas soluble

refers to a solid dissolving into solution in a liquid.
52

5.2 Chemical and Physical Differences between Raw Bitumen and Other 

Crudes

5.2.1 Formation of Oil Sands

Alberta oil sands most likely formed from a standard crude oil deposit that underwent 

a significant amount of biodegradation (USGS, 2007; Shuqing et al., 2008). The lighter, 

shorter chain alkanes in the petroleum mixture were subject to degradation by naturallyoccurring microorganisms, leading to a partially-weathered product with a predominance

of large molecules. The biodegradation occurred because the bitumen reserves never 

exceeded 80̊ C, meaning pasteurization (sterilization) could not occur (Shuqing et al., 

2008). The conditions necessary for biodegradation are: a low ambient reservoir temp; 

the presence of an electron acceptor such as water; an oil-water contact; microorganisms; 

and nutrients (Shuqing et al., 2008). For more in-depth discussion on the origin of bitumen 

reserves in Alberta, see Shuqing et al. (2008).

The amount of biodegradation that may occur after a spill of oil sands products will be 

dependent on the extent to which the material was degraded prior to extraction. 

Therefore, bitumen that has undergone a high degree of biodegradation will probably 

undergo little biodegradation after a spill (Dettman, 2013). However, there are no 

experimental data available to fully evaluate the biodegradation potential oil sands 

products spilled into fresh or salt water systems. 

5.2.2 Bitumen Chemical Properties

Biodegradation of oil leads to relative increase in sulfur, resins, asphaltenes, and 

metals (Shuqing et al., 2008). In the process of biodegradation, microorganisms initially 

attack small organic compounds, leaving large compounds behind. In situ biodegradation 

of crude oil leads to bitumen containing a lower proportion of paraffins (saturated 

hydrocarbons without rings) and naphthenes (saturated hydrocarbons with rings), and a 

higher proportion (>50 percent) of aromatics (hydrocarbons with one or more aromatic 

nuclei), which leads to the increased viscosity and density characteristics of bitumen 

(USGS, 1990). Netzer et al. (2006) found that aromatics made up 37 percent of the total 

weight of Athabasca bitumen, followed by resins (25.7 percent), and by saturates and 

asphaltenes (both 17.3 percent). Yang et al. (2011) determined through gas 

chromatography that Alberta bitumen was characterized by large, unresolved compounds 

(n-C10 to n-C40) and a near absence of n-alkanes. Souraki et al. (2012) found that C39 and 

larger molecules made up 56.96 percent of the weight of Athabasca bitumen. See Table 1 in 

Heavy Oil and Natural Bitumen Resources in Geological Basins of the World (USGS, 2007) for 

a numeric breakdown of many of the chemical properties of bitumen.
53

5.2.3 Bitumen Physical Properties

Locating information on the physical properties of Alberta oil sands products can be 

challenging, as some of the specific physical and chemical properties data are considered to 

be proprietary business information. For this reason, it has been difficult for regulators 

and others in the scientific community to access and predict physical behavior in the 

environment (Jensen and Pilkey-Jarvis, personal communication, 2012).

Bitumen is generally characterized as being denser than standard crude oils (USGS, 

2007; Shuqing et al., 2008). The density of bitumen, when compared to water, depends on 

the specific reservoir and temperature of the source material. Athabasca bitumen tends to 

be denser than freshwater, but less dense than saltwater, under standard conditions of 

15.56̊ C and 20 bara/19.74 ATM (Netzer, 2006; Souraki et al., 2012). Between 25 and 40̊ C, 

Athabasca bitumen becomes less dense than water (Mochinaga et al. 2006). Cold Lake 

bitumen is denser than freshwater below ~40̊ C but less dense than saltwater (Mehrotra & 

Svercek, 1988). Barrufet & Setiadarma (2003) found that bitumen is less dense than water 

at ambient temperature, although they do not specify from which reservoir the sample was 

obtained. As temperature increases, the viscosity and density decrease. Bitumen can be

orders of magnitude more viscous than conventional oils. At 25̊ C, the viscosity of 

conventional crude is ~13.7 cP, while for bitumen it is >1,000,000 cP (USGS, 2007). 

Athabasca bitumen must approach 200̊ C, before its viscosity is similar to standard crude 

oil viscosity at ambient temperatures (Souraki et al., 2012). Cold Lake bitumen must 

exceed 120̊ C before its viscosity is similar to standard crude viscosity at ambient 

temperature (Mehrota & Svrcek, 1988). See Table 1 in USGS (2007), for a more detailed

comparison of the physical properties of bitumen relative to heavy, medium, and 

conventional oils.

API values for crude oils range from approximately <22-42, with refined products and 

condensates ranging higher. A summary of crude oil and other petroleum product 

densities is as follows.

•

•

•

•

•

•

Gas Condensates – ≈ 42 to 55°API

Light Crude Oils – ≈ 31 to 42°API - varies

Medium Crude Oils – ≈ 22 to 31°API 

Heavy Crude Oils – ≈ <22°API

Alberta Bitumen – ≈ 8°API prior to being mixed with diluent

Water (≈10°API); Gasoline (≈63°API); Fuel Oil #2(≈30-38°API)

See Appendix 2 for more data values and ranges for the relevant oil sands products 

being exported from Canada (Environment Canada, 2013; USGS, 2007; USDOT PHMSA, 

2012).
54

5.3 API, Specific Gravity, Acidity, and Other Data for Oil Sands Products

5.3.1 Floating, Sinking, and Submerged Oil

5.3.1.1 Floating Oil

Most crude and refined oil products float when spilled. As a result, spill response 

agencies are most familiar with and best equipped to handle floating oil spills.

12 However, 

depending on the environment and conditions specific to a given location, a spill of a very 

light conventional crude oil does not always float. For example, in the 2010 Deepwater 

Horizon spill in the Gulf of Mexico, small droplets of light oil released below the surface 

remained submerged despite having API gravity greater than 10, because the turbulence

and water movement was enough to overcome the buoyancy of the small particles of oil 

(Joint Analysis Group, 2012). While this oil would have behaved differently had it not been 

a subsurface release, it demonstrates the variation in oil fate based on the circumstances 

under which it is spilled and the environment into which it is spilled. 

5.3.1.2 Sinking Oil

Some oils, including Group V products (defined as having a specific gravity greater 

than 1.0) can sink, sometimes reaching the ocean floor or riverbed (National Research 

Council, 1999). However, specific gravity, as used in the regulatory definition of Group V 

oils, does not adequately characterize all oil types and weathering conditions that may 

result in non-floating oils, which has led to the “non-floating” or “submerged oil” definition 

below.

5.3.1.3 Non-floating and Submerged Oil

Non-floating oils behave differently and have different environmental fates and effects 

than floating oils. As might be expected, the resources at greatest risk from spills of floating 

oils are those that use the water surface and the shoreline. Floating-oil spills have fewer 

impacts on water-column and benthic resources (although as we have noted, specific 

conditions with specific oils can result in sub-surface oil). These non-floating oil spills can 

pose an increased threat to water-column and benthic13 resources (National Research 

Council, 1999). This includes Group IV oil, which has a specific gravity of slightly less than 

1.0 and “might mix into the water column and sink to the seabed after weathering and 

interaction with sediments” (National Research Council, 1999). This can make effective 

recovery difficult if not impossible, because skimmers and other surface technologies, as 

well as remotely operated vehicles (ROVs) that would be able to recover oil from the 

bottom are both rendered ineffective (Goodman, 2006).14 Oils that have density values 

12 See Section 7 for more on response technology. 

13 The term benthic refers to organisms living on or in sea or lake bottoms.

14 See Section 7 for more on response technology.

 
55

very close to that of water can become neutrally buoyant, and remain suspended in the 

water column. These interact with the environment in a variety of ways, including:

•

•

•

Association with suspended sediment particles in turbid water, especially in rivers 

during flood stage, estuarine waters, or any other water carrying sediment (National 

Research Council, 1999).

Turbulence in the water can move neutrally buoyant oil—or oil with a density very 

close to that of the surrounding water—vertically in the water column. During the 

Enbridge Kalamazoo River spill response, turbulence along the river bottom caused 

sunken oil to resurface (Muller, 2013).

When oil is spilled and enters the environment, there is the likelihood for

temperature changes. Any decreases in temperature will cause the oil’s density to 

increase, further increasing the chance of becoming submerged. Similarly, increases 

in ambient temperature may bring submerged oil to the surface.

5.3.2 Implications of Physical Properties in Spill Scenarios

5.3.2.1 Saltwater

Due to the salt content, seawater is denser than fresh water, with an API gravity value 

of approximately 6.0 (specific gravity ranging from 1.02-1.03) (Glencoe, 2002). Depending 

on the reservoir or origin, raw, undiluted bitumen produced from oil sands products can 

have API gravity below 10 (specific gravity of 1), meaning that it would sink in fresh water. 

The dilbit and synbit mixtures being transported in pipelines and by rail typically have 

been blended with lighter petroleum in the form of diluents or processed into “synthetic 

crude” and have higher API densities (Environment Canada, 2013). The addition of lighter 

material may sufficiently change the density to allow the product to initially float if spilled 

in fresh or saltwater.

Although other sources (listed above) portray dilbit as lighter than water, the 

Keystone XL Draft EIS, released by the U.S. State Department on March 1, 2013 listed

specific gravity values for dilbit that range on either side of water. This may be related to 

the specific product samples analyzed (U.S. Department of State, 2013). Additionally, an 

API density close to 10 suggests that variations due to temperature or other environmental 

factors could change the way the product behaves in a spill. The density of fresh oil also 

changes as a result of weathering processes. For example, as diluents and other lighter 

molecules begin to evaporate from an oil sands product, the remaining material becomes 

denser. No experimental data are currently available to evaluate how oil sands products 

will behave when spilled in saltwater environments. Of particular interest is whether oil 

sands products could sink or submerge after weathering, interaction with sediments, or 

other conditions that could be encountered in the environment.
56

5.3.2.2 Freshwater

The largest and most-documented example of a dilbit spill into freshwater is the 2010 

Enbridge pipeline spill into Michigan’s Kalamazoo River, which included both Cold Lake 

Blend and Western Canadian Select crude oil condensate mixtures. These dilbit blends 

have a reported specific gravity of 0.65 to 0.75 (NTSB, 2010). According to responders and 

damage assessment specialists who worked on-scene monitoring and advising the 

response effort from its early stages, the spill presented unique challenges atypical of

traditional crude oil spills (J. Winter, NOAA, personal communication, 2012; L. Muller, 

USEPA, personal communication, 2013). Because oil begins to weather as soon as it enters 

the environment, some of these unique challenges resulted from the specific conditions in 

which the spill occurred. It is, however, difficult to isolate the role the physical properties 

of Cold Lake Blend and Western Canadian Select played in determining the fate of the oil 

spilled in Michigan. Responders from the EPA, NOAA, and the NTSB report stated that 

containment and cleanup efforts required responding to floating, submerged and sunken 

oil (NTSB, 2010; J. Winter, personal communication, 2012; L. Muller, personal 

communication, 2013). Initially, there were surface slicks and a visible sheen of oil on the 

water, but during the course of the cleanup, responders also found “blobs” of oil moving in 

the water column as well as sunken oil on the river bottom (J. Winter, personal 

communication, 2012; L. Muller, personal communication, 2013). Flood conditions, 

turbidity, and the velocity and volume of the river at the time of the spill all influenced the 

behavior of the oil once it was spilled (NTSB, 2010). Responding to oil sands products 

released into this kind of dynamic fresh water environment would be particularly 

challenging especially in warm summer weather, because the lighter diluents would 

presumably evaporate and leave the heavier components of the product. If these heavy 

ends were sufficiently dense—and especially if they mixed with sediment— the oil could 

have submerged or sunk.

5.3.2.3 Estuarine Water and Puget Sound

Estuarine water presents its own set of unique challenges when trying to model or 

predict the behavior, weathering, and fate of spilled oil. The flow of fresh water into 

seawater from rivers with differing temperatures, salinity, and density can cause the water 

column to become stratified or drive the formation of other unique features. In Puget 

Sound, it is the influx of riverine water that is the primary cause of and control for 

stratification in that body (Climate Impacts Group, 2005). Because the mixing with fresh 

water dilutes the salinity, estuarine water is less dense than oceanic saltwater. In addition, 

because it is less dense, the less saline riverine water resides in the upper layers of the 

water column, meaning that heavier oil spilled into the estuarine waters of Puget Sound 

would be more likely to submerge or sink than the same oil spilled in the open ocean. This 

would be a consideration for the waters around potential terminal sites like Grays Harbor, 

WA and Kitimat, B.C., where major rivers influence local conditions. Predicting and 
57

preparing for a spill of oils sands product in Puget Sound or other estuarine environments 

requires accounting (to the extent possible) for these varying factors that affect water 

density and oil behavior. 

5.3.3 Information Gaps for Physical Properties

•

•

•

•

The API densities listed on the commonly referenced Environment Canada website 

may be out of date or incomplete. At least some of the values there were originally 

published in 1983.

Physical properties of oil sands-derived products fluctuate based on season, 

customer requirements, and other factors (Dettman, 2013).

Pipeline operators may not necessarily know detailed information related to 

products in the pipeline at the time and location of a release (Dettman, 2013).

The lack of experimental data on the weathering behavior of oil sand limits the 

ability of spill response organizations to understand and predict the behavior and 

fate of oil sands products in freshwater, estuarine, and saltwater environments.

5.4 Diluents

5.4.1 Diluents and Synthetic Crude

According to Enbridge (2010) specifications, the diluents used in the transport of oil 

sands products are light hydrocarbons with a typical density between 0.6-0.775 g/ml, a 

maximum weight by percent of 0.5 percent for sulfur, and maximum viscosity of 2.0 cST 

(7.5̊ C). Natural gas condensate, a liquid that under standard, ambient conditions contains 

pentanes and heavier hydrocarbons produced from processing natural gas, is currently the 

most commonly used diluent (Bott, 2011). Additional pipelines have been proposed to 

supply diluent to Alberta and meet the growing demand for, but decreasing supply of, 

diluents in Canada (CAPP, 2011).

Another approach to upgrading bitumen is to blend it with synthetic crude oil to make 

a product called “synbit.” Synbit is a mixture of bitumen with synthetic crude—bitumen

that has undergone upgrading through coking and hydrolysis to remove the larger 

molecules and decrease viscosity (Yui, 2008; Héraud, 2011; U.S. Department of State, 2013) 

(See Yui (2008) for a simplified schematic of the synthetic crude upgrading process). 

Currently, this method is less expensive than mixing the bitumen with diluent (Héraud, 

2011). Projections show that the use of synthetic crude as a diluting agent will increase 

over the next decade, while the use of natural gas condensate will remain steady (Héraud, 

2011).

The characteristics of diluents vary with across the range of products. Please refer to

Crude Quality Inc. (2013) for an in-depth list of the physical and chemical properties of 

several diluents.
58

5.4.2 Dilbit and Synbit Composition for Transport

The composition of dilbit varies between 25-30 percent diluent and 70-75 percent

bitumen, depending on the viscosity of the bitumen and the density of the diluent (Héraud, 

2011). The ratio can be as high as 40 percent diluent for heavier bitumen (Bott, 2011). 

The diluent required for mixture can be decreased if the asphaltene fraction is removed 

from the parent bitumen (Rahimi & Gentzis, 2006). Because the diluent and bitumen are 

both hydrocarbon-based, the two are completely miscible (Dettman, 2013). For synbit, the 

mixture is typically 50 percent synthetic crude and 50 percent bitumen (Héraud, 2011).

5.4.3 Information Gaps for Diluents

As we have noted, diluent properties will differ with the specific properties of the 

bitumen being transported and with the diluent type chosen. These can range from high to 

low in sulfur content, have highly variable boiling points, and fundamentally different 

chemistries. Because of the potential differences in the diluent component of an oil sands 

product, generalizing about characteristics and environmental behaviors is not possible; 

obtaining as much detailed information as possible about the product of concern will 

greatly aid in spill response considerations related to occupational exposure and 

environmental toxicity.

5.5 Weathering of Dilbit in the Environment

5.5.1 Weathering of Oil Sands Derived Products Relative to Conventional Heavy Crude 

Oils

Currently, there is very little information about weathering characteristics of oil sands 

products released into the environment. Some studies have been conducted in the 

laboratory and investigated specific products, but not a comprehensive range of the oil 

sands products being transported out of Canada (SL Ross, 2012). One of these studies, 

conducted by SL Ross Environmental Research Limited tested MacKay River Heavy 

Bitumen and Cold Lake Bitumen diluted with synthetic crude (Suncor Synthetic Light) and 

condensate (CRW condensate), respectively. The study concluded that artificiallyweathered oil sands mixtures approached, but did not exceed, the density of water. In 

other words: the oils did not sink. At the end of the tests, approximately 15 percent of the 

recovered oil was collected from the tank walls 10 cm below the water surface. The 

majority (approximately 85 percent) of the oil was recovered from either the surface or 

stuck to the side walls within 10 cm of the surface. At no point was oil found to submerge, 

sink, and stick to the bottom of the flume (SL Ross, 2012).15 These results, however, 

represented a few of a myriad of possible weathering scenarios, were limited by the 

15 A complete description of their methods and findings can be found in the report SL Ross published, cited in the 

references section.
59

experimental conditions and scale, and would be expected to vary with different products 

or experimental environments. Although other more comprehensive studies are 

underway,16 the empirical knowledge base is currently limited to what can be gleaned from 

the response efforts of the few dilbit spills that have occurred (See section 7.2 Response 

Efforts).

The available information suggests that dilbit, synbit, and other bitumen-based 

products contain more “heavy ends,” or large hydrocarbon molecules, than conventional 

crude oils. Additionally, because oil sands products have already undergone partial 

biodegradation in their formation process, the extent of any further biodegradation after 

the initial weathering of the diluent portion of the mixture17 is largely unknown.

5.5.2 Potential Weathering Patterns in the Environment

When oil is spilled into the environment it begins to “weather” due to physical, 

chemical, and biological factors in the environment. Effectively modeling the weathering of 

any oil—including oils sands products—requires knowing the particular properties of that 

product, including density, pour point, and distillation curves. While regulatory agencies

and spill responders generally have good data on the properties of conventional crude oils, 

they are much less likely to have accurate information on the properties of oils sands 

products. Limited information is available for a few products—for example, Cold Lake 

Blend—but not many of the other bitumen-diluent blends or synbits being produced.

Gathering the characteristics to accurately model weathering behavior may be 

difficult for oil sands products. The physical properties of crude oil from conventional 

reservoirs typically change slowly over years, making their behavior easier to model at any 

given time. In contrast, physical composition of the oil sands products being transported 

out of Alberta can vary greatly and are not readily generalized. Not only do the physical 

properties of bitumen deposits vary across the region, the mixtures entering the 

transmission lines after being upgraded and or diluted can vary on a weekly basis. Each oil 

sands product entering a pipeline differs, based on specifications from the refineries 

receiving the product (Dettman, 2013). All crude oils contain a spectrum of hydrocarbons, 

with each portion, or “cut,” used to make different products—i.e. gasoline, asphalt, plastics, 

etc. Refineries frequently change the mix requested based on demand for specific products.

Some evidence exists that because oil sands products are heavier and more viscous 

than conventional crude oils, they may be more challenging to clean up. In the event of a 

spill on land, “the heavier and more viscous components (i.e., the asphaltenes) would likely 

16 According to a webinar talk given by Kinder Morgan on February 13th 2013 they have engaged O’Brien’s Response 

Management and Polaris to study fate of oils sands products. They have completed the literature review, gap analysis and 

research plan, and are scheduled to do research March 2013 and issue final report by April 2013. They intend to include 

tests of typical oil sands products under ambient conditions similar to those of the Salish Sea. Tests on API by the National

Academy of Science on diluted bitumen are also currently underway.

17 See section 5.1 for more on biodegradation and the history of Canada’s oil sands deposits.

 
60

remain trapped in soil pores above the water table. It is also likely that the lighter 

constituents would partly evaporate and not be transported down through the soil with the 

heavier components.” (Ramseur, et al, 2012). These properties would also make cleanup 

challenging in the event of a spill into water. The potential for the lighter diluent to 

evaporate relatively quickly, leaving the heavier bitumen, equates to an increased risk that 

responders could be dealing with oil in more than a single part of the water column. These 

predictions would be consistent with the experience of responders at the Kalamazoo River 

spill (J. Winter, personal communication, 2012; L. Muller, personal communication, 2013).

5.5.3 Information Gaps for Modeling Weathering

•

•

•

The variability in potential mixtures of oil sands products due to differences in 

source materials, and the range of mixtures possible to accommodate different 

modes of transport, different seasons, and different requirements specified by 

refiners suggests a highly complex modeling environment will be necessary for spill 

response.

Regulatory and response agencies are at present likely to have insufficient 

information about what product is being transported through a pipeline at any 

given time, and lag time associated with getting accurate data from the producer or 

pipeline operator may impede attempts to model behavior and effects, and cause 

delays to the response and cleanup efforts.

Experimental and field data on the potential for further biodegradation of spilled oil 

sands products is currently inadequate. 

5.6 Corrosiveness of Oil Sands Products

5.6.1 Overview of Existing Research on Pipeline Corrosion

A recurring source of contention in discussions about the risks of transporting oils 

sands products via pipelines has centered on corrosion and the inherent corrosivity of 

those products relative to traditional crude oil. Several research reports exist on the 

subject of oil sands products corrosiveness (see the “Key Sources of Information” below), 

and although not entirely conclusive, the data suggest that in general oil sands products are 

not significantly more corrosive than other heavy crude oils being transported through 

pipelines. A brief overview of the findings includes the following points:

• Sulfur content of Alberta oil sands products ranges between 2-5 (weight percent). 

There are conflicting reports regarding how these sulfur levels compare to other 

heavy crude oils. The report by Zhou and Been determined oil sands products to be 

generally comparable to other heavy crudes, with the exception of a few specific 

products (Zhou, and Been, 2011). However, a U.S. Geological Survey study reported
61

higher sulfur content as a fundamental difference between natural bitumen and 

conventional crude oils as a result of in situ biodegradation (USGS, 2007). 

•

•

•

•

•

TAN values of Alberta oil sands products ranged from .5-2.5 (mgKOH/g), which is 

comparable to many conventional heavy crudes. Products with TAN values higher 

than 0.5 are generally considered “potentially corrosive” (Ramseur et al, 2012), but 

in lab testing the oil sands products were not found to be significantly different than 

comparable heavy crudes and not corrosive enough to be a concern to pipeline 

operators (Dettman, 2012), (Zhou, Been, 2011).

Water content (BS&W) in oil sands products is comparable to other crudes, with the 

required maximum allowable threshold set by pipeline operators (Dettman, 2012; 

Owens, 2012).

Sediment content in dilbit crudes was found to be lower than or comparable to that 

of conventional crudes, with the exception of one dilsynbit blend that was found to 

have more than double the solids content of most other crudes (Zhou and Been, 

2011). The data, however, only indicate the total amount of sediments and do not 

provide information on the size distribution. It is unknown how the solids in the 

conventional crudes compared to those in dilbits (Zhou and Been, 2011).

Sediment build-up in low or high spots in the pipeline interior can lead to corrosion 

(Dettman, 2012; NTSB, 2010).

According to some experts, water content is still the most important factor in the 

potential for pipeline corrosion (Dettman, 2012).

Our research does not indicate that oils sands products are significantly more 

corrosive than other heavy crude oils. A National Academy of Sciences study currently 

underway and scheduled to be complete by the end of 2013 will analyze whether 

transportation of dilbit by transmission pipeline is subject to an increased likelihood of 

release compared with pipeline transportation of other crude oils. The National Academy 

study will primarily be a review of existing literature and will not include any original 

research. PHMSA data presented to the National Academy show that since 2002 there have 

been no releases of oil caused by internal corrosion from pipelines carrying dilbit (API, 

2012). However, this does not mean that corrosion is not a concern: combined internal 

and external corrosion account for 37 percent of non-small pipeline accidents for crude oil 

(PHMSA, 2012c).

5.6.2 Water and Sediment Content

After being mined from the ground, oil sands go through a series of pipelines called 

“gathering lines” or “feeder lines” during initial extraction and processing. During these 

early stages, the raw product can have diluent mixed with it, and may also contain 

naturally-occurring elevated levels of sediment and water. Consequently, these gathering 

lines are more prone to corrosion, and require maintenance every three months. However, 
62

once the product enters the larger crude oil lines that transport the oil sands products out 

of Alberta, it has been semi-processed and the sediment and water content have been 

reduced. Consequently, corrosion is less likely (Dettman, 2012).

Key Sources: Properties, Fate, and Behavior of Oil Sands Products

Comparison of the Corrosivity of Dilbit and Conventional Crude, by Zhou and Been. Commissioned by 

Alberta Innovates

Congressional Research Service Report: Oil Sands and the Keystone XL Pipeline: Background and Selected 

Environmental Issues

Crude Monitor: http://www.crudemonitor.ca/

Environment Canada Oil Properties Database: http://www.etccte.ec.gc.ca/databases/OilProperties/oil_prop_e.html

Heather Dettman, Petroleum Research Scientist at Natural Resources Canada.

Presentation: National Academy of Sciences Transportation Research Board Study of Pipeline 

Transportation of Diluted Bitumen Pipeline and Hazardous Materials Safety Administration Briefing

Shuqing, Z., Haiping, H., and L. Yuming. (2008). Biodegradation and origin of oil sands in the Western Canada 

Sedimentary Basin. Petroleum Science, 5, 87-94. 

U.S. Geological Survey. (2007). Heavy Oil and Natural Bitumen Resources in Geological Basins of the World. 

(Open File-Report 2007-1084).Reston, Virginia: Meyer, R.F., Attanasi, E.D. & Freeman, P.A., retrieved from 

http://pubs.usgs.gov/of/2007/1084/OF2007-1084v1.pdf
63

6 ENIVRONMENTAL AND HUMAN HEALTH EFFECTS OF OIL SANDS 

PRODUCTS

6.1 Environmental Impacts

6.1.1 Species at Risk During Floating and Sinking Phase

Oil spills can have both immediate ecosystem impacts as well as long-term 

consequences resulting from continued chronic exposure (Peterson et al., 2003). The route 

of exposure to oil for species at risk can be an important determinant of impact, including 

whether it is a short- or longer-term effect. An obvious consideration in evaluating 

potential impact to resources at risk is the behavior of the oil itself, i.e., does it float, sink, or 

do something in between? At least some oil sands products require us to think about 

water-based impacts and responses in three dimensions, to consider oil potentially 

affecting the surface, water column, and benthic habitats. In addition, spill impacts from oil 

sands products include those from the partitioning of diluent into the air and water, as well 

as the components of the source bitumen that could differentially partition into the water 

column and sediments. 

6.1.1.1 Species at Risk During Floating Phase

During floating oil spills, species that contact the surface of the water frequently are at 

highest risk. This can include aquatic and semi-aquatic mammals, sea birds and waterfowl, 

turtles, and aquatic insects. Aquatic and semi-aquatic mammals, depending on species, can 

suffer acute mortality through hypothermia from loss of insulation, oil ingestion, and 

inhalation of toxic fumes (EPA, 1999). Mammals that rely on fur for insulation are highly 

vulnerable (USFWS, 2010). Sea otters, river otters, beavers, and fur seals, are particularly 

susceptible to the effects of oil exposure resulting from their frequent contact with the 

water’s surface and their reliance on fur for insulation (EPA, 1999). Seabirds and 

waterfowl are also subject to acute mortality through loss of waterproofing and insulation, 

and oil ingestion. These species at risk would be the same as those at risk during any 

similar floating oil spill.

6.1.1.2 Species at Risk During Submerged and Sinking Phase

Fish eggs laid on bitumen-contaminated sediments in lab studies showed frequent 

death or physical abnormalities, including spinal deformities, lesions, hematomas, and eye 

defects (Colavecchia et al. 2004; Colavecchia et al., 2006; Colavecchia et al., 2007). 

Therefore, if a spill involving sunken oil occurs during spawning periods, fish eggs and 

larvae may be adversely affected (Peterson et al., 2003). Coral communities can also be 

adversely affected by submerged oil (White et al., 2012a, White et al. 2012b). Oil can 

continue to affect marine mammals through ingestion especially in species that come into
64

contact with contaminated sediments or feed on bivalves (Peterson et al. 2003). Shellfish, 

which typically depurate oil hydrocarbons slowly, can be adversely affected if oil sinks, 

submerges, or becomes concentrated near shorelines (USFWS, 2010). Through gill uptake 

or ingestion of oil or contaminated prey, fish may be subject to adverse health impacts 

(USFWS, 2010). The presence of residual polycyclic aromatic hydrocarbons (PAHs) after oil 

spills is known to be harmful to fish larvae, including those of pink salmon and herring 

(Peterson et al. 2003).

6.1.1.3 Species at Risk From Diluent

According to the Material Safety Data Sheet for sour natural gas condensate from 

ConocoPhillips (2012), condensates can cause lasting effects in aquatic environments and 

are considered to be toxic to aquatic organisms. In general, natural gas condensate is 

moderately to highly toxic via inhalation, and thus could pose problems for all species that

breathe at or near the surface (e.g., marine mammals and sea turtles). As the diluent is 

liquid under ambient conditions, it can dissolve or disperse into the water column, with 

potentially detrimental effects for fish and aquatic insects.

6.1.2 Athabasca River Studies

Although not directly oil spill related, studies investigating the effects of oil sands 

development on the Athabasca River provide some insights into potential impacts of toxic 

materials in the bitumen itself. Observed impacts include:

•

•

•

•

•

Fish that came into contact with oil mining tailings-associated water developed 

adverse immunological effects (McNeill et al. 2012).

Fish eggs laid on bitumen-contaminated sediments showed either adverse physical 

abnormalities including spinal deformities, lesions, hematomas and eye defects, or 

death (Colavecchia et al., 2004; Colavecchia et al., 2006; Colavecchia et al., 2007).

While fish physical abnormalities have been reported downstream of oil sands 

development (Schindler, 2010), a direct causal link could not be established.

Kelly et al. (2010) found increased levels of the 13 elements considered priority 

pollutants in either melted snow or water samples from near or downstream of 

development. Seven of these pollutants—cadmium, copper, lead, mercury, nickel, 

silver, and zinc—surpassed either Canada’s or Alberta’s guidelines for the 

protection of aquatic life. 

PAH’s were significantly higher downstream of oil sands development, 10 to nearly 

50 fold higher, when compared to areas not subject to land disturbance (Kelly et al., 

2009). Some of the values exceeded concentrations known to be toxic to fish

embryos. It was speculated that during spring snowmelt, PAH values could exceed 

toxicity levels for both aquatic and terrestrial organisms.
65

• Trends in mercury levels in fish populations close to and downstream of oil sands 

products development have been reported with starkly different conclusions: 

Timoney & Lee (2009) found an increase in mercury levels in fish from 1976-2005, 

while Evans & Talbot (2012) found a decrease in mercury levels in fish species from 

1981-2011. The reason for the conflicting results may be attributable to research 

methodology (Evans & Talbot, 2012).

6.1.3 Information Gaps for Environmental Impacts

•

•

•

Toxicity information specific to oil sands products is scarce. Although existing 

results for discrete petroleum components like heavy oils or bitumens, natural gas 

condensates, or synthetic crude oils exist, the toxicological and environmental 

effects of the many different permutations of oil sands products are relatively 

unknown.

One of the most important determinants of effect will be the behavior of the spilled 

oil sands products in the environment; that is, will they float, sink, or become 

neutrally buoyant in receiving waters. As previously noted, this is extremely 

difficult to predict, given the range of oil mixtures and the range of environmental 

conditions that may be potentially encountered.

Studies conducted near oil sands development offer some insights into potential 

effects of the products. Current water, snowpack, and air monitoring for toxic 

outputs near oil sands development are not sufficient (Kelly et al., 2009; Schindler, 

2010) for full environmental assessment. The Regional Aquatics Monitoring 

Program (RAMP) has collected information from monitoring water quality and fish 

populations in the Athabasca River but recent literature has elucidated several 

issues with the current program (Kelly et al., 2009; Schindler, 2010; Royal Society of 

Canada, 2010; Jordaan, 2012). Ongoing monitoring of potential fish tainting may 

also be an important component of an overall monitoring program to determine the 

impact of oil sands development (Tolton et al., 2012).

6.2 Human Health Impacts

6.2.1 Human Health Concerns Near Oil Sands Products Development

No evidence currently exists suggesting people who live in the vicinity or downstream 

of oil sands sites near the Athabasca River are subject to increased health concerns (Royal 

Society of Canada, 2010). Two studies noted the link between cancer and PAHs, and that 

increased PAH levels could potentially cause increases in downstream cancer risk, but a 

conclusive link between increased PAHs in the Athabasca river and cancer cases has not 

been made (Royal Society of Canada, 2010). An elevated number of cancer cases has been 

observed 250km downstream from oils sands development in Fort Chipewyan, but again, 

this was not attributable to the upstream oil sands development (Chen, 2009; Royal Society 
66

of Canada, 2010). When compared to the values specified in the Guidelines for Canadian 

Drinking Water Quality (GCDWQ), antimony, arsenic, cadmium, chromium, copper, lead, 

mercury, selenium, and zinc did not exceed the recommended values at or below oil sand 

development sites near the Athabasca River (Kelley et al. 2010; Royal Society of Canada, 

2010). Please refer to Environmental and Health Impacts of Canada’s Oil Sands Industry 

(Royal Society of Canada, 2010) for a more in depth discussion of human health risks in the 

areas near oil sands products development sites. 

6.2.2 Safety of Cleanup Crew and Citizens in the Spill Vicinity

The responders to the dilbit spill in Kalamazoo, MI, reported elevated levels of 

benzene in the air relative to those recorded at spills of standard crude oils (L. Muller, 

2013). Evaporation of diluent could pose an inhalation risk to responders and others in a 

spill-affected zone, but the question of whether the diluent fraction of an oil sands product 

mix evaporates more rapidly than the lighter fractions of a typical crude oil remains open. 

The answer has important implications for responder safety and potential residential 

exposures, particularly under warm weather conditions.

It is not known if other compositional differences between oil sands products and 

typical crude oils affect risk levels for exposed people. For example, bitumen is 

characterized as being richer in sulfur than conventional oil (Shuqing et al., 2008), lower in 

mercury and higher in lead content (USGS, 2007). However, there are no indications that 

these result in increased risk during a spill.

The diluent added to a mixture could potentially pose problems due to its low flash 

point; meaning combustion could be a problem from the evaporation of diluent. The 

Material Safety Data Sheet (MSDS) for ConocoPhillips (2012) and Gibsons (2012) natural 

gas condensate lists the product as extremely flammable. ConocoPhillips (2012) further 

warns that condensate is toxic and potentially fatal if inhaled resulting from the hydrogen 

sulfide gas content. The MSDA for Hess (2012) lists sweet natural gas condensate as only 

marginally toxic through inhalation probably because of lower hydrogen sulfide levels. 

Benzene, a known carcinogen, is also present in natural gas condensate, which could pose a 

risk to spill responders. The MSDS for Hess (2012), ConocoPhillips (2012), and Gibsons 

(2012) recommend spill responders wear air supplied respirators, protective clothing, and 

eye protection. The MSDS for natural gas condensate for Oneok (2009) warns that 

condensate, being heavier than air, will accumulate in depressions. These MSDS 

recommendations and warnings are for natural gas condensate alone; the risks from 

natural gas condensate after blending to form dilbit would be expected to be different.

Following the Enbridge spill in Kalamazoo, MI, 320 community members and 11 spill 

responders reported adverse health effects which included headaches, nausea, and 

respiratory issues (Michigan Department of Community Health, 2010; NTSB, 2010). Refer 

to the report Acute Health Effects of the Enbridge Oil Spill (2010) produced by the Michigan 
67

Department of Health for a list and statistical breakdown of the observed adverse health 

effects.

6.2.3 Information Gaps for Human Health Impacts

The important gaps in information related to human health impacts of oil sands 

products during spills and spill responses largely center on the composition diluent 

component of the mixture and uncertainties regarding the behavior of the diluent in the 

environment.

•

•

•

More information is necessary to understand whether oil sands product blends 

weather differently from comparable crude oils. Specifically, it is not known if the 

diluent portion of an oil sand mixture has significantly different evaporation kinetics 

than the light fractions of a crude oil.

It is possible that the evaporated diluent component of an oil sands mixture could 

present a higher explosive risk than would be expected for crude oils, although it 

should be noted that many crude oils contain a relatively high proportion of volatile 

chemicals with low flash point.

Specific information about the diluent added to an oil sands mixture of concern 

would be key to more accurately determining risk to responders and nearby human 

communities.

Key Sources: Environmental and Human Health Effects of Oil Sands 

Products

EPA, Office of Emergency and Remedial Response. (1999). Understanding oil spills and oil spill response (EPA 

540-K-99-007). Retrieved January 10, 2013, from 

http://www.epa.gov/osweroe1/content/learning/pdfbook.htm

Michigan Department of Community Health. (2010). Acute health effects of the Enbridge oil spill. Lansing, 

Michigan: Stanbury, M., Hekman, K., Wells, E., Miller, C., Smolinske, S., & Rutherford, J. Retrieved from 

http://www.michigan.gov/documents/mdch/enbridge_oil_spill_epi_report_with_cover_11_22_10_339101_7.

pdf

Royal Society of Canada. (2010). Environmental and health impacts of Canada’s oil sands industry. Ottawa, 

Ontario: Gosselin, P., Hrudey, S.E., Naeith, M.A., Plourde, A., Therrien, R., Van Der Kraak, G., & Xu, Z. Retrieved 

from: http://rsc-src.ca/en/expert-panels/rsc-reports/environmental-and-health-impacts-canadas-oil-sandsindustry

Schindler, D.W. (2010). Tar sands need solid science. Nature, 468, 499-501.
68

7 RISK MITIGATION

The U.S. government has in place a number of systems that are meant to mitigate the 

risks associated with the transportation of oil. In this section, we will examine three 

potential issues: 

1. The siting process of pipelines at the state and international level;

2. Systems to detect pipeline leaks; and

3. Spill response equipment with the ability to handle heavy oil spills.

These three issues are important in the discussions about oil sands products as they 

provide insight in the ability and capacity for the U.S. government, as well as private 

companies, to prepare for and respond to spills of the products. 

7.1 Risk Mitigation Techniques

7.1.1 Pipeline Siting

The federal government, through the U.S. State Department, approves or rejects the 

construction of pipelines whenever the proposed route crosses a U.S. border (Parfomak et 

al., 2013). However, the federal government is not involved in the siting of any intrastate 

or interstate pipelines.18 In both cases, state law determines the appropriate regulatory 

agency that approves the siting and construction of large energy infrastructure projects. 

The procedures and regulatory agency in charge of siting pipelines varies from state to 

state (Parfomak et al., 2013). In this section, we will review the factors that the U.S. State 

Department considers when making pipeline approval decisions, and also examine the 

state requirements in Washington. 

7.1.1.1 Presidential Permit Application

Pipeline operators constructing an international pipeline must apply for a 

Presidential Permit through the U.S. State Department (the “Department”). The 

Department has a considerable amount of discretion in its decision-making process; 

however, its main goal is to determine if the project is within the “national interest” 

(Parfomak et al., 2013). To accomplish this, the Department considers (Parfomak et al., 

2013): 

18 The Federal Energy Regulatory Commission (FERC) is in charge of approving construction of interstate natural gas 

pipelines, however, this authority does not extend to oil pipelines. FERC’s involvement with interstate pipeline includes 

regulating the rates and practices of oil pipeline companies, establishing equal service conditions to provide shippers with 

equal access to pipeline transportation, and the establishment of reasonable rates for transporting petroleum and 

petroleum products by pipeline (FERC, 2013).

 
69

•

•

•

•

•

•

•

Environmental impacts of the proposed project;

Potential for the proposed project to diversify U.S. energy supplies and meet 

demand;

Security of the pipeline at the border crossing, specifically in relation to other modes 

of transport;

Stability in the relationship of trading partners;

Impact of the proposed project on foreign policy goals;

Economic benefits of the project; and

Proposed project’s impacts on U.S. goals of reducing fossil fuel dependence.

The Department must also take into account any potential impacts the proposed

pipeline may have on the National Historic Preservation Act, the Endangered Species Act, 

the National Environmental Policy Act, and Executive Order 12898, which addresses

environmental justice concerns (Parfomak et al., 2013). Of these policies, the National 

Environmental Policy Act (NEPA) traditionally is the most discussed. NEPA requires 

federal agencies to consider the environmental impacts of proposed projects and provides 

a forum for stakeholders to express their concerns (Caldwell, 1998).

NEPA requires the completion of an Environmental Impact Statement (EIS). EISs 

occur in two stages: a draft stage and a final stage. When a draft EIS is submitted to the 

State Department, it is then made available to the public for a mandated comment period. 

The final EIS must incorporate the comments from the public by either explaining why the 

concern was not considered or by explicitly addressing the concern in the final draft 

(Caldwell, 1998). The U.S. Environmental Protection Agency (EPA) must publically 

comment on the draft EIS and evaluate both how well the EIS analyzes the environmental 

impacts of the alternatives (adequacy) and the level of environmental impact of the 

proposed action (impact) (EPA, 2012c). 

Based on the EPA’s ratings of the draft EIS and the public’s comments, the project 

proposer either revisits the draft proposal or incorporates the comments to create a final 

EIS. After the final EIS is submitted to the State Department, there is a final 90-day review 

period during which the Department gathers information from relevant agencies and 

stakeholders to determine if the project is within the national interest (Parfomak et al., 

2013). 

7.1.1.2 Washington State Requirements

In Washington State, all intrastate pipelines carrying crude, refined, or liquid 

petroleum products must be approved by Washington’s Energy Facility Site Evaluation 

Council (EFSEC). The EFSEC is responsible for evaluating applications and ensuring that all 

environmental and socioeconomic impacts are considered before a pipeline is approved. 

Applicants must address over 60 environmental and socioeconomic impact objectives 

(including measures to mitigate impacts), submit an environmental impact statement, and 
70

defend themselves at public hearings before their projects can be approved. After 

evaluating the application, EFSEC will submit its recommendation to Washington’s 

Governor. If the Governor approves the project, a Site Certification Agreement (SCA) is 

issued and construction can begin (EFSEC, 2012). EFSEC is also the regulatory agency that 

provides oversight during the construction and operation of the facility. It has the 

authority to levy fines or halt construction if it deems that the project is violating state laws 

or the conditions of the SCA (EFSEC, 2012). 

7.1.1.3 Stakeholders and other factors in pipeline siting

In order to increase the political feasibility of a large infrastructure project, such as 

the siting of a pipeline, there are a number of factors that should be taken into account 

beyond economic and environmental benefits or concerns. These include (Nussbaum, 

2012):

•

•

•

•

•

•

•

•

Wildlife management areas, including all parks, national forests, and public lands;

Other pipelines and utilities that cross the proposed route;

Roads, railroads, and water crossings;

Jurisdictional boundaries of states, counties, and cities;

Native American or First Nation ownership or interests;

Federal and State threatened or endangered species’ habitat;

Wetlands and other environmentally sensitive properties; and

Private land.

The proposed pipelines mentioned below have faced opposition and been delayed 

due to a number of these factors. For example, the Enbridge Northern Gateway pipeline is 

being opposed by First Nations because the proposed route crosses their land, whereas the 

Keystone XL pipeline has been delayed for multiple years because its proposed route 

crossed environmentally sensitive areas in Nebraska and because of the additional 

regulations imposed on pipelines that cross U.S. borders.

Key Sources: Pipeline Siting

EFSEC. (2012). Siting/Review Process. Retrieved 2013 18-February from Energy Facility Site Evaluation 

Council: http://www.efsec.wa.gov/cert.shtml#Certification

Parfomak, P. W., Pirog, R., Luther, L., & Vann, A. (2013). Keystone XL Pipeline Project: Key Issues.

Congressional Research Service. CRS.

Nussbaum, M. (2012 Jan/Feb). Pipeline Route Selection. Right of Way, 35-36.
71

7.1.1.4 Status of Each Proposed Pipeline

Four major pipelines are being planned to increase the transport of oil sands products 

from Alberta to consumer markets. These pipelines include Enbridge’s Northern Gateway 

pipeline, Kinder Morgan’s Trans Mountain (TM) Expansion, TransCanada’s Keystone XL, 

and Enbridge’s Line 9 Reversal. Enbridge’s Northern Gateway and Line 9 Reversal and 

Kinder Morgan’s TM Expansion19 are within Canadian borders, whereas the Keystone XL 

crosses the U.S. – Canadian border. The status of each pipeline, as of March 2013, is 

provided below as Table 7–1. 

Table 7-1. Status (as of March 2013) of proposed pipeline projects for transporting Alberta oil products.

Pipeline Regulatory Status

Start of 

Construction20 Operational Major Opposition

Northern 

Gateway

• Began Joint Review 

Panel on 8/3/2012 to 

assess environmental 

impacts, public 

comments, Aboriginal 

concerns, and gather 

information.

• Hearings will 

continue through May 

2013 (NEB, 2013a). 

Mid-2014 

(Enbridge, 2013)

2017

(Enbridge, 

2013)

• Fear for Fraser and 

Skeena River Salmon 

populations (WCEL, 

2012).

• Stanch opposition 

from First Nation 

Groups, with over 130 

Nations signing the 

"Save the Fraser 

Declaration" 

(McKnight, 2012).

• Sixty percent of B.C. 

residents oppose the 

pipeline (Flegg, 2012)

TM 

Expansion

• Toll application was 

submitted in 2012.

• Plan to file facilities 

application in late 

2013.

• Expect decision from 

the National Energy 

Board (NEB) in 2014 

(Kinder Morgan, 

2013b)

2016 (Kinder 

Morgan, 2013b)

2017 (Kinder 

Morgan, 

2013b)

• Largest opposition is 

from local groups in 

Vancouver that are 

concerned with the 

lack of additional 

marine safety 

procedures for the 

harbor.

• Traverses Jasper 

National Park in the 

Canadian Rocky 

Mountains and some of 

Canada's most 

productive farmland in 

the Fraser Valley (Lee, 

2013)

19 Note that Kinder Morgan’s expansion is occurring between Edmonton, Alberta and Burnaby, B.C. The expansion does 

not include the segment of the pipeline that crosses the U.S. border, which is why it does not require State Department 

approval.

20 Pending Approval

 
72

Pipeline Regulatory Status

Start of 

Construction20 Operational Major Opposition

Keystone 

XL

• Denied Presidential

Permit in 2/2012.

• Reapplied in 5/2012

with a new route in

Nebraska that avoids

the environmentally

sensitive Sand Hills

region.

• Decision is expected

in early 2013

(TransCanada, 2013).

• All states directly

affected by the

Pipeline have

expressed support

(Jones, 2013; Olson

2013). 

• Received approval

from Canada's NEB in 

2010 (TransCanada, 

2012). 

Southern section 

from Oklahoma to 

Texas is already 

under 

construction. The 

second section, 

from Alberta to 

Nebraska, is 

expected to begin 

in mid-2013 

(TransCanada, 

2012)

Late 2014 or 

early 2015;

Southern 

section, late 

2013 

(TransCanada, 

2013)

• Main opposition is

from environmental

groups and

landowners.

• The largest delay was

the opposition from

the State of Nebraska,

which just recently

approved the pipeline

route (NPR, 2012).

Line 9 

Reversal

• Hearing completed in

5/2012.

• Approval to reverse

the 9A pipeline was

obtained in 7/2012

(NEB, 2013b).

• NEB is currently

reviewing the request

to reverse and

expand Line 9B from

Ontario to Quebec

(Enbridge, 2012b).

No construction 

(Enbridge, 2012b)

Early 2014 

(Enbridge, 

2012b)

• Since this isn't a new

pipeline, the major

opposition has been to

the transportation of

oil sands products.

• To bring the oil to the

Atlantic, the

Portland/Montreal

pipeline will also have

to be reversed in the

future (Nelson, 2012)

7.1.2 Pipeline Modes of Failure and Leak Detection Technologies

There are four main categories of pipeline failure (Chris, 2007):

•

•

•

•

Pipeline corrosion and wear, caused by corrosive products, atmospheric effects, 

external corrosion, or leaving a pipeline partially full for a period of time;

Operation outside design limits;

Unintentional third party damage; and

Intentional damage.

The most common source of pipeline failure is from external corrosion, specifically 

caused by water eroding the outside coating of the pipeline (Dettman, 2013). This may 
73

have been a contributing factor in the Kalamazoo spill, as there were high floodwaters at 

the time of the rupture and significant external corrosion was found at the rupture site 

(Dettman, 2013; NTSB, 2010). 

7.1.2.1 Types of Spill Detection

Pipeline operators use a number of techniques to detect pipeline leaks. Spill detection 

methods are not meant to prevent spills, but to alert operators of spills so they can respond 

in a timely manner. Traditionally, leak detection methods can be broken down into three 

different categories (Zhang, 1996):

•

•

•

Traditional methods: using personnel to walk or fly the line and visually inspect

unusual patterns on the pipeline route, such as discolored vegetation;

Hardware-based methods: localized leak detection that identifies changes in 

temperature, noise, presence of gas, and negative pressure at specific points; and

Software-based methods or Leak Detection Systems: various computer programs that 

monitor the changes in flow, pressure, temperature, and other hydraulic data. The 

most successful software-based method involves dynamic modeling, which attempts 

to mathematically model the flow within the pipeline and detect discrepancies 

between calculated and measured values.

7.1.2.2 Leak Detection Systems

Currently, software-based methods or Leak Detection Systems (LDS) are the only 

method of spill detection that offers real-time, continuous monitoring down the length of 

the pipeline (Song, 2012). LDS work by sensing abrupt changes in the flow rates and 

pipeline pressure and then triggering an alarm when discrepancies occur.

When analyzing the success of LDS, it is important to consider the ability of the 

system to detect the location of the leak, the extent of the leak, and the possibility of a false 

alarm (Jiang et al., 2009). Positives of using LDS include (Song, 2012):

•

•

•

High success rates in detecting large spills and ruptures;

24/7, 365 day monitoring; and

In theory, these systems can detect a spill and shut down the flow of oil in the 

affected pipeline segment within 10 minutes.

7.1.2.3 False Alarms and Leak Detection Systems

One of the main issues with LDS is that controllers have to decide whether an alarm is 

in an actual leak or a false alarm. The more sensitive a system is to the loss of 

hydrocarbons, the higher the rate will be of false alarms (Shaw, et al., 2012). If a system is 

sensitive to the loss of hydrocarbons and false alarms are commonplace, it may condition 

controllers to assume that the majority of alarms are false alarms. This can, in turn, lead to 
74

controllers losing confidence in the system and ignoring real warnings, as was the case in 

the Kalamazoo spill (Zhang, 1996; Shaw, et al., 2012; NTSB, 2010). 

One aspect of pipeline operation that contributes to false alarms is the occurrence of 

column separation. Column separation, or “slack flow,” is the breaking of liquid columns in 

a fully-filled pipeline (Bergant et al., 2006). This occurs when the pressure in the pipeline 

becomes low enough to allow the light ends of the oil to vaporize within the pipeline, 

creating a sort of “bubble.” When the pressure of the pipeline naturally rises, the bubble 

can collapse, which will cause the pressure in the pipeline to surge. This phenomenon may 

occur at high elevation points or when there are large changes in elevation, and is common 

in all crude oil pipelines, not just dilbit (Dettman, 2013). The issue with column separation 

is that the pressure surges will register a “leak” with an LDS and indicate a false alarm 

(NTSB, 2010). 

7.1.2.4 Criticisms of Leak Detection Systems

Other than the high occurrence of false alarms, there are a number of criticisms about 

relying on LDS to detect spills. According to a study commissioned by PHMSA (Song, 2012):

•

•

•

•

LDS detected only 5 percent of the nation’s pipeline spills between 2002 and 2012. 

The general public detected 22 percent of the spills and on scene employees 

detected 62 percent. 

LDS are not effective at identifying smaller spills, especially those that leak slowly. 

Smaller spills of this kind are much more common among pipeline infrastructure.

Pipelines with variable flow rates, such as the Keystone XL, make it difficult to 

estimate how much oil is supposed to be in the pipeline at a given time.

Pipeline companies’ procedures have allowed alarms to be ignored by controllers, 

assuming that the alert is a false alarm instead of a real threat.

Two recent spills document the dangers of relying on LDS to detect spills. In both 

cases, human error, specifically hesitation in shutting down the system after an alarm 

sounded, led to excessive amounts of oil spilling into the natural environment:

• Kalamazoo River Spill: Enbridge asserted that the pipeline spill detection sensors 

would remotely detect and lead to a shut down within eight minutes of a rupture. 

However, after the initial alarm sounded in the Kalamazoo River incident, it took 17 

hours for the pipeline operators to confirm the spill and shut down the pipeline 

segment. The controllers assumed that the alarm was due to column separation and 

not a leak. As a result, the controllers restarted the line and pumped more oil 

through the pipeline in order to “fix” the problem. The safety board concluded that 

the workers had not been sufficiently trained to recognize a spill alarm, which was a 

primary contributor to the severity of the spill (NTSB, 2010).
75

• Yellowstone Spill: In 2010, over 1,500 barrels of ExxonMobil crude oil (not dilbit) 

was released into the Yellowstone River. The rupture was detected in the control 

room and the pipeline was partially isolated seven minutes after recognizing failure. 

However, as ExxonMobil employees discussed next steps, crude continued to flow 

into the river for 48 minutes, until the upstream valve was closed and the pipeline 

segment was fully isolated. Human delay resulted in approximately 6.2 times more 

crude spilling into the river than would have been the case if the upstream valve 

was closed at the initial alarm (DOT, 2012). 

7.1.2.5 Expected Use of LDS with New Pipelines

Both Enbridge and TransCanada have released statements supporting the use of LDS 

to detect spills on their proposed pipelines. In public discussions about LDS, the two 

companies have made clear that they are aware of the potential shortcomings of relying on 

LDS and stated that it will be one of many tools used to detect spills. Public meetings have 

reflected detection of leaks to be a substantial public concern.

TransCanada has stated that the Keystone XL will have the best LDS technology in the 

world (TransCanada, 2013). The company estimates that its LDS will be able to detect 

spills at or above 1.5 percent of the pipeline’s flow. This translates to spills of 12,450 

barrels or larger (Song, 2012). To detect spills smaller than the 1.5 percent threshold, 

TransCanada stated that it will use static pressuring. However, this method would require 

TransCanada to periodically shut down operations for testing (Song, 2012). TransCanada 

has also agreed to adopt 57 measures that will hold it accountable for surpassing the legal 

minimum requirements in risk reduction methods. These conditions include burying the 

pipeline deeper underground than required, installing a higher number of data sensors and 

remote controlled shut-off valves, and increasing inspections and maintenance 

(TransCanada, 2013). TransCanada would also conduct aerial patrols every two weeks 

(TransCanada, 2013). Enbridge stated that it will use multiple approaches for leak 

detection that include computational pipeline monitoring, controller monitoring, line 

balance calculations, and aerial patrols at least once every two weeks (NEB, 2012). 

Kinder Morgan has not described its intended use of LDS beyond general, nonspecific

information on its website (Kinder Morgan, 2012). However, the Trans Mountain 

Expansion project date is further in the future than the TransCanada and Enbridge projects, 

and therefore such operational details may not be necessary at this point in time.
76

Key Sources: Pipeline Modes of Failure & LDS

Dettman, Heather (January, 2013). Personal Communication. 

Song, L. (2012 19-September). Few Oil Pipeline Spills Detected by Much-Touted Technology. Retrieved 2013 

11-February from Inside Climate News: http://insideclimatenews.org/news/20120919/few-oil-pipelinespills-detected-much-touted-technology

7.1.3 Information Gaps in Risk Mitigation Factors

In this section, two major risk mitigation methods were discussed: the process of 

approving the construction of pipelines at the federal and state level and the use of leak 

detection systems to detect leaks. Three main information and knowledge gaps exist in this 

discussion: 

•

•

•

In this report, we did not discuss the siting process of interstate pipelines due to 

time constraints. One question did emerge regarding this topic: do pipeline 

companies need to pursue separate approval processes in every state that the 

pipeline will cross or is there a separate regulatory agency, or certain states, that are 

in charge of approving the construction of interstate pipelines?

There are many criticisms of relying on leak detection systems to detect spills. 

TransCanada and Enbridge have stepped forward to describe how leak detection 

systems will be used in their risk mitigation strategies. However, a gap still remains 

in understanding how much the pipeline operators are relying on leak detection 

systems to detect spills and if this dependence is providing a false sense of security.

There is doubt about the ability of operators to differentiate between false and real 

threats when interpreting leak detection systems’ alarms. It is unknown if the 

training these pipeline companies are providing is adequate to create a reliable 

detection system.

7.2 Response Efforts

Two water-borne spills of oil sands products have recently occurred: the Kalamazoo 

River Spill in Marshall, Michigan (dilbit) and the Burnaby Harbor Spill in Burnaby, British 

Columbia (synthetic crude). Like all spills, these reflect unique circumstances and settings, 

limiting the ability to extrapolate lessons learned about oil sands products behavior and 

response methods. Due to the small number of case studies, this section will also examine 

the Wabamun Lake Spill, a railcar derailment that spilled Bunker C oil, a heavy fuel oil, into 

a freshwater system in Alberta, Canada.
77

7.2.1 Kalamazoo River Spill

Two types of dilbit oil were spilled during the Enbridge pipeline spill into the 

Kalamazoo River system: Cold Lake and McKay River Heavy (Miskolzie, 2012). Enbridge 

initially reported the size of the release to be 819,000 gal.; this was later revised upward to

843,000 gal. (USEPA, 2013b). Other estimates by the EPA have been substantially higher, 

up to 1.1 million gal. The reasons for the discrepancies in spilled volume estimates are not 

clear and have not been resolved, but will be a factor in determining Clean Water Act 

penalties (Song, 2013).

The dilbit initially floated on the fresh water. However, after mixing with sediments 

and the evaporation of the light hydrocarbons, some oil became heavy and sank (Miskolzie, 

2012). As a result, there were ties during the response when the dilbit was simultaneously 

floating, submerged in the water column, and on the bottom of the river. Beyond the 

characteristics of the oil, the water temperature, the presence of sediments, and the speed 

of the river affected oil recovery (Miskolzie, 2012). See section 2.1.1 for more information 

about this spill.

7.2.1.1 Technologies Used in Recovery

An important issue impeding oil removal efforts during the Kalamazoo River spill was 

the fast moving water of the river and Talmadge Creek (NTSB, 2010). Recovering oil in fast 

moving water is difficult, as oil tends to flow under containment booms and skimmer

efficiency is greatly reduced, necessitating more rapid responses further downstream 

(USCG, 2001). In these situations, the United States Coast Guard (USCG) recommends 

installing underflow dams, overflow dams, sorbent barriers, or a combination of these 

techniques (NTSB, 2010).

Enbridge responders, with personnel from Terra Contracting and the Baker 

Corporation, used:

•

•

•

•

•

Oil booming and sorbent booming at 33 oil spill containment-and-control points. At 

the most heavily boomed location, 176,124 feet of boom was deployed (NTSB, 

2010).

One gravel-and-earth underflow dam at the meeting of the contaminated marsh and 

Talmadge Creek. This site was chosen because it was accessible to heavy 

equipment. Responders did not have the traditional materials for adjustable 

underflow dams on site and had to construct one out of surplus materials and 

therefore were late deploying the technology (NTSB, 2010).

Three vacuum trucks were used to recover oil at the underflow dam. Nine other 

vacuum tracks were deployed at other sites (NTSB, 2010).

Oil skimmers were also used to recover oil (NTSB, 2010). 

On 25 acres, dredging was used to recover oil (NTSB, 2010). This method was the 

most successful in terms of the amount of oil recovered (Muller, 2013).
78

• Responders considered plugging the steel culvert pipe under Division Drive with 

earth to contain the oil upstream, but the quick water flow prohibited attempting 

this method (NTSB, 2010).

At the peak of deployment, 2,011 personnel engaged in oil spill recovery (NTSB, 

2010). As of summer 2013, the cleanup efforts were continuing. In October 2012, EPA 

directed Enbridge to dredge approximately 100 acres of the Kalamazoo River, as oil 

continued to accumulate in three areas (EPA, 2012d). The main concern with the presence 

of this oil was that during a flood, the pools of oil could remobilize and contaminate parts of 

the river that had already been cleaned (Hasemyer, 2012). EPA chose to move forward 

with dredging because it was deemed the most effective method during the original 

recovery efforts (EPA, 2012d). Enbridge contested EPA’s assessment, stating that further 

dredging would do more harm than good to the Kalamazoo River ecosystem (Adams, 

2012). In March 2013, EPA ordered another round of dredging to remove submerged oil 

and oil-contaminated sediments upstream of the Ceresco Dam, in the Mill Ponds area, 

around Morrow Lake, and installation of sediment traps at two locations (USEPA, 2013b). 

The required dredging was to be completed by the end of 2013.

7.2.1.2 Lessons Learned regarding Recovery Efforts

Three main issues were identified related to Enbridge’s recovery efforts:

1. Communication –The spill occurred during the night and initial responders were not 

aware of the severity of the spill or the type of oil spilled (Muller, 2013), which led 

to poor decision-making (NTSB, 2010). Responders had no estimate of a volume 

release when the first round of containment methods was deployed (NTSB, 2010).

2. Lack of resources – Originally, Enbridge responders did not have the resources to 

contain or control the flow of oil into the surrounding bodies of water (such as 

materials for underflow dams). Enbridge initially brought in contractors from 

Minnesota, a 10-hour drive away from the site, which slowed recovery time (NTSB, 

2010). The EPA on-scene coordinator provided Enbridge with the contact 

information for local contractors to keep recovery efforts moving forward (NTSB, 

2010).

3. Lack of Training – During the initial response, Enbridge personnel placed the 

containment booms too far downstream to be effective, and also used booms that 

were incompatible with fast-moving water (NTSB, 2010). This was related to both 

lack of training, and also the lack of communication and knowledge regarding the 

severity of the spill.
79

7.2.2 Burnaby Harbor Spill

7.2.2.1 Spill Summary

On July 24, 2007, approximately 1,400 barrels (58,800 gal.) of synthetic crude leaked 

from the Westridge Transfer Line in Burnaby, British Columbia. After the oil was spilled, it 

flowed in Burnaby’s storm sewer systems until it reached Burrard Inlet (TSB, 2008a). In 

total, eleven houses were sprayed from the rupture, fifty properties were affected, 250 

residents voluntarily left, and the Burrard Inlet’s marine environment and 1,200 meters of 

shoreline were affected by the spill (TSB, 2008a).

Five minutes after the rupture, the pipeline operator shut down the Westridge 

Pipeline and the Westridge dock delivery valves were closed. However, the Burnaby 

Terminal is sited at a higher elevation than the rupture site, so gravity intensified the 

release of the oil. Twenty-four minutes after the rupture, the Burnaby Terminal and the 

Westridge Pipeline were fully isolated. Kinder Morgan established a unified command with 

the British Columbia Ministry of Environment and the National Energy Board (NEB) to 

coordinate the response. The initial failure to fully shutdown the Westridge Pipeline was 

contrary to Kinder Morgan’s standard shutdown procedures (TSB, 2008a). Cleanup took 

months and cost roughly $15 million and resulted in the recovery of approximately 1,321

barrels of oil (CBC, 2011).

In 2011, three companies – two contracting companies and Trans Mountain Pipeline 

L.P. – pleaded guilty to violating the Environmental Management Act for introducing 

pollutants into the environment, and will each pay a $1,000 fine and donate $149,000 to 

the Habitat Conservation Trust Foundation (CBC, 2011). Trans Mountain Pipeline L.P. will 

be required to pay an additional $100,000 to fund training and education programs (CBC, 

2011). See section 2.1.4 for more information on this spill.

7.2.2.2 Technologies Used in Recovery

Kinder Morgan primarily relied on contractors to recover the oil (Ministry of the 

Environment, 2007). The contractors used three distinct methods to recover the oil, based 

on the oil’s location (Penner & Sinoski, 2007): 

1. Residential areas. Peat moss was used successfully to absorb oil on land. 

2. Storm Sewers. Oil in the storm sewers was vacuumed up. Much of the oil was 

collected in the pump station.

3. Burrard Inlet. The responders were able to set up floating booms outside the storm 

sewer tunnels to collect oil that reached the Inlet. To treat the oil that had adhered 

to the shoreline, responders successfully used the chemical shoreline cleaner 

Corexit 9580 (Shang et al., 2012). 
80

7.2.2.3 Lessons Learned

The recovery effort during the Burnaby Harbor spill was relatively successful. 

Because the synthetic crude traveled on a predictable path through the storm sewer 

system, the responders were able to set up booms in a quick and efficient manner. We 

were not able to find any reports of the oil sinking or being submerged in the water 

column. However, extrapolating the oil behavior in this case to other potential synthetic 

crude spills is difficult because most of the oil was collected in the storm sewer systems 

and on land.

The primary issue in this case study was the lack of communication between city 

contractors and Kinder Morgan during the excavation process. Also, by failing to follow 

standard emergency procedure after a spill was detected, more oil was released into the 

natural environment. As with the Kalamazoo spill, failure to follow administrative 

procedures significantly increased the amount of oil spilled.

7.2.3 Wabamun Lake Spill

7.2.3.1 Spill Summary

Forty-three Canadian National Railway (CN) freight railcars derailed on August 3, 

2005 adjacent to Lake Wabamun, just west of Edmonton, Alberta. The derailment resulted 

in 4,400 barrels of Bunker C oil and 554 barrels of a pole treating oil being spilled, with 

approximately 1235 barrels21 of the oil entering the temperate Lake Wabamun (Fingas, 

2010; TSB, 2008b). The spill was caused by a faulty train track that had a least 13 

undetected defects (CBC, 2007). Though Bunker C is not an oil sands product, it is a heavy 

oil and can have a density approaching that of water, and thus could be similar to undiluted 

bitumen. In this case, the oil began to sink with limited amounts of weathering and 

sedimentation (Goodman, 2006).

CN used an oil response contractor to recover the spilled oil. However, after the 

contractor’s initial efforts, it became clear that it was not sufficiently experienced in oil 

spills of this magnitude or of this type of oil. As a result, it was not able to contain the spill 

and CN eventually had to contract the cleanup to a more experienced response 

organization (TSB, 2008b). The new response contractor began by using the Shoreline 

Cleanup and Assessment Technique (SCAT) and then moved to cleaning up individual 

shore segments (Goodman, 2006). A number of reed beds were cut because the reeds 

became a continuing source of surface contamination (Goodman, 2006). In total, 

approximately 1,076 barrels of oil was recovered and the response effort was completed in 

October 2005 (Severs, 2005).

During the clean up, there was strong public perception that the government failed to 

do its job, specifically, that the recovery efforts were more concerned with getting the track 

21 The amount of oil that entered Lake Wabamun is debated and varies greatly depending on the source. This estimate is 

an average of the most commonly cited amounts.

 
81

cleared and working again than with any ecological effects. This was compounded by the 

delay in beginning cleanup efforts due to lack of available equipment (Goodman, 2006). As 

a result, the Alberta Ministry of the Environment established the Environmental Protection 

Commission in August of 2005 after the spill (Goodman, 2006); First Nations sued CN and 

were awarded $10 million. CN spent approximately $132 million in cleanup costs and paid 

$1.4 million in fines, and additionally made changes to its spill procedures and equipment 

requirements (Goodman, 2006).

7.2.3.2 Technologies Used in Recovery

Two main elements were taken into consideration during the Lake Wabamun spill 

response: weather and the type of oil spilled. Both of these elements affected the behavior 

of the spilled oil, such as when the oil submerged and entered the water column or when 

the oil sank to the bottom (Fingas, 2010). Responders used the following technologies:

•

•

•

•

•

•

•

•

Sorbent and containment booms were the first technologies deployed at the site. 

Sorbent booms were ineffective in containing the Bunker C oil and there were not 

enough containment booms to stop the spread of oil due to high winds (Goodman, 

2006). It was necessary for additional equipment to be brought in from across 

Canada and the United States (TSB, 2008b).

Dikes were successfully built to stop the flow of oil into the lake. Once the ditches 

and dikes were completed, no further oil reached the lake (TSB, 2008b).

Vacuum trucks helped recover the oil (TSB, 2008b).

Hand shoveling and skimmers were relatively successful (TSB, 2008b).

Sorbent pads were used to probe the bottom of Lake Wabamun in order to detect oil 

that had settled on the bottom. The Bunker C oil had formed a skin and did not 

adhere to the pads, making this technology ineffective (Goodman, 2006).

Video cameras for detection were only successful in some shallow water situations 

due to the dispersed nature of the oil (Goodman, 2006).

Nets of ten millimeters were ineffective. Responders had to move toward very fine 

netting, which inhibited water flow. Ten-millimeter nets were tried due to the 

previous success with this size of net in collecting bitumen (Goodman, 2006).

Responders had very limited success recovering oil once it reached the bottom 

(Goodman, 2006).

It is important to note that it was not until four days after the derailment that 

responders realized that the pole treating oil had been spilled as well. The pole treating oil 

being transferred was mixed with other chemicals to be used as a wood preservative. This 

type of substance may contain toluene, benzene and its derivatives, naphthalene and its 

derivatives, phenyls, and polycyclic aromatic compounds (PACs) (TSB, 2008b). As a result, 
82

the workplace hazard associated with the chemical was neither recognized nor 

communicated until days later (TSB, 2008b).

7.2.3.3 Lessons Learned from Spill

The spill response effort at Wabamun Lake was not efficient particularly due to 

management decisions (TSB, 2008b). An emergency operations center under the unified 

command system (UC) was not set up. Under UC, response agencies collaborate on the 

response effort, with the main purpose to provide guidelines for multiple agencies to work 

together efficiently (TSB, 2008b). This was the Transportation Safety Board of Canada’s 

(2008b) main criticism of CN’s response efforts. Other shortcomings observed during the 

response effort included: 

•

•

•

•

Limited amounts of response equipment in close proximity to the spill. This was 

problematic as it led to both negative public relations as citizens witnessed the oil 

spreading without an adequate response, as well as responders missing crucial time 

in containing the spill (Goodman, 2006). Later, it was determined that some 

response equipment in the region was not made available because it was held in 

reserve in case of a concurrent environmental disaster (TSB, 2008b).

The need for contingency planning. CN implemented its Dangerous Goods Emergency 

Response Plan but failed to install a unified command (TBS, 2008b). The lack of a 

central structure led to considerable confusion in the early stages of recovery as 

more responders arrived on scene and there was no organizational structure to rely 

on (Goodman, 2006). Also, the contingency plan CN had in place was generic and 

had no specific guidelines for the Wabamun Lake area. The plans had not been 

tested recently and there had been little contact with response groups in the area 

(Goodman, 2006).

Lack of information regarding the behavior of heavy oil when spilled. In this case, the 

lack of information regarding the interaction of oil and fine sediments and how the 

changes in surface water temperature would influence submerged oil, tar ball 

formation, and the long-term fate of submerged oil in marine and fresh water 

ecosystems affected clean-up efforts (Goodman, 2006).

Limited number of tested and effective oil detection technologies. Response crews 

lacked appropriate technology for detecting oil once it reached the bottom of the 

lake (Goodman, 2006).
83

Key Sources: Response Efforts

NTSB. (2010). Enbridge Incorporated, Hazardous Liquid Pipeline Rupture and Release, Marshall, Michigan, 

July 25, 2010. National Transportation Safety Board, Pipeline Accident Report. Washington D.C.: NTSB.

Goodman, R. (2006). Wabamun: A Major Inland Spill. Innovative Ventures Ltd. Cochrane: IVL.

TSB. (2008a). Pipeline Investigation Report, Crude Oil Pipelines -- Third-Party Damage, TransMountain 

Pipeline L.P. 610-Millimetre-Diameter Crude Oil Pipeline. P07H0040, Transportation Safety Board.

TSB. (2008b). Railway Investigation Report R05E0059, Derailment Canadian National Freight Train M30351-

03 Mile 49.4, Edson Subdivison Wabamun, Alberta 03 August 2005. Transportation Safety Board of Canada. 

TSB.

7.2.4 Information Gaps in Response Efforts

This section concentrated on past response efforts for oil sands products spills and 

one case of a heavy oil spill. Due to the small number of case studies, a number of research 

and information gaps remain. One research gap stands out based on the above discussion:

• As the Kalamazoo spill suggested, weathering and sedimentation may lead to the oil 

being overwashed by water, suspended in the water column, or sinking to the 

bottom. There is a gap in understanding how oil sands products are affected by the 

weathering and sedimentation processes and also the time frame when these 

processes will affect the success of spill response.

The three case studies discussed above also have similarities related to the 

ineffectiveness of management during the spill response. This leads to the question:

• Are the current plans, training procedures, and equipment resources adequate in 

preventing significant amounts of oil from entering the natural environment?

7.3 Effectiveness of Current Equipment on Sunken and Submerged Oil Spills

7.3.1 Assumptions

The following analysis was based on the assumption that oil sands products will 

remain on the surface for several hours or days when spilled into saltwater, but as 

sedimentation and volatilization occurs, some of the oil will submerge or sink (Counterspil 

Research, 2011). This assumption was supported by Enbridge technical data reports

released in conjunction with the proposed Northern Gateway pipeline project. The reports 

suggested that in a marine spill scenario, 80 percent of the oil would remain on the surface 

for 120 hours under summer conditions (i.e., would not easily sink) but “will be easily 

overwashed with water” (Counterspil Research, 2011). Due to the lack of available case 
84

studies on oil sands product spills, this analysis evaluated equipment effectiveness in past 

heavy oil spills, where the oil was submerged in the water column or sank. This is relevant 

to the oil sands discussion, as oil sands products may behave like non-floating oils after 

weathering and other interactions with the environment. 

7.3.2 Common Oil Spill Recovery Technologies and Anticipated Effectiveness

7.3.2.1 Detection and Monitoring of Submerged and Sunken Oil

Based on U.S. Coast Guard research, multi-beam and imaging sonars are the most 

effective technologies for conducting wide area detection surveys and searching for large 

pools of subsurface oil. The sonars are most effective in detecting subsurface pools if the

equipment is deployed before the oil breaks up. However, the resolution of these devices 

remains relatively low, impairing their effectiveness. Laser systems and narrower beam 

sonars are better suited to narrow areas and determining the amount of oil present 

(Hansen et al., 2009). A summary of other detection and monitoring technologies are 

provided in the Table 7−2. For a full analysis of detection and monitoring equipment, see 

Appendix 3.
85

Table 7-2. Summary of detection and monitoring methods for sunken and submerged oil.

Technology Analysis 

Snare Sampler •

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

Specifically used to detect oil at various depths in the water column

Produces time-series data

Time and labor intensive (Counterspil Research, 2011; Michel, 2006)

Vessel-Submerged Oil 

Recovery System (V-SORS)

Can detect both pooled and mobile oil moving along the bottom

Relatively efficient

Time and labor intensive

Susceptible to snagging on bottom (Counterspil Research, 2011; Michel, 

2006)

Side-scan sonar data Provides good spatial coverage and visualization of large accumulations 

and bottom features

Effectiveness diminishes as the oil spreads and the water becomes rough

More successful in detecting the trenches and other bottom features that 

contain pooled oil instead of the oil itself (Counterspil Research, 2011; 

Michel, 2006)

RoxAnn Used to differentiate seafloor bottoms (Michel, 2006; Counterspil 

Research, 2011)

Remotely-operated 

underwater video

Successfully provides estimates of frequency and size of oil 

accumulations

Cannot always determine exact oil position

Effective with visibility exceeding 0.5 meters, but it does not generate a 

wide view (Counterspil Research, 2011)

Sorbents attached to 

weights

Ineffective (Counterspil Research, 2011)

Sorbent drops and 

sediment cores

Not effective for mobile oil in the water column (Michel, 2006)

Snare Sentinels Too time and labor-intensive for widespread use (Counterspil Research, 

2011; Michel, 2006)

Airborne Hyperspectral 

fluorescent LiDar

Successful in detecting oil suspended in the top few meters below the 

water surface

RESON Sonar System Positively identifies 87 percent of sunken oil targets.

Has a false alarm rate of 24 percent (Hansen et al., 2009)

EIC Fluorosensor Can be attached to ROVS or other platforms

GIS input fluctuates and direct mapping is not possible (Hansen et al., 

2009)

Side-looking Airborne 

Radar, UV, & IR

Unable to penetrate water
86

7.3.2.2 Containment of Submerged and Sunken Oil

Containment of submerged oil remains mostly in the conceptual stage. To the extent 

that the below (Table 7–3) technologies have proven effective, it has been limited to lowflow zones or depressions (Counterspil Research, 2011).

Table 7-3. Summary of potential containment methods for sunken and submerged oil.

Technology Analysis 

Trenching and Berming •

•

•

•

•

•

•

•

•

•

•

•

•

•

Does not work if the oil is suspended

Pneumatic barriers (air 

bubbles)

Limited information on this method

May aerate oil, which would change the density and reduce the 

oil's tendency to sink.

Effective at "protecting a water intake at currents of less than 0.75 

knots" (Counterspil Research, 2011)

Deep-skirted booms Developed to contain Orimulsion

May be effective, but have limited information (Counterspil 

Research, 2011)

Bottom booms, filter fence, 

trenches, and booms

Can be coordinated with recovery and are quick and easy to 

deploy

Highly dependent on bottom conditions

Seabed booms for sunken oil have not been tested in a real 

situation (Counterspil Research, 2011)

Trawl nets Have proven effective (other than fine mesh nets)

Made specifically for heavy oil recovery (Counterspil Research, 

2011)

Sorbent barrier/fence Never tested

Engineering design inadequate to assure it would function 

properly

If manipulated, it can be easily fabricated to meet site-specific 

contexts (Michel, 2006)

7.3.2.3 Removal of Submerged and Sunken Oil

If oil is suspended in the water column, little can be done besides detecting the oil 

(Counterspil Research, 2011). During the 2005 heavy oil spill from the tank barge DBL-152 

in the Gulf of Mexico, hydraulic submersibles featuring open impeller chambers, such as the 

MPC model KMA axial/centrifugal pump, and directed by divers proved to be most 

successful in removing sunken oil (Counterspil Research, 2011). U.S. Coast Guard research 

suggests that a hopper dredge or large duck-bill system has the highest potential for use in 

recovery efforts based on timing, operational limits, recovery efficiency, remobilization, 

cost, and safety (Michel, 2006). Potential recovery methods for sunken and submerged oil 

are summarized in Table 7−4. 
87

Table 7-4. Summary of potential recovery methods for sunken and submerged oil.

Technology Analysis

Hydraulically-driven 

submersible dredge 

pump with a diverdirected suction hose

•

•

•

•

•

•

•

•

•

•

•

•

•

Recovered 900 gallons of submerged, pooled oil from small trench during M/T 

Athos

Diver directed hoses led to a slow recovery, especially since the oil was moving 

(Counterspil Research, 2011)

Centrifugal Pump Resulted in droplet formation

Used with a lower rpm Foilex TDS-150 Archimedes screw pump as well as a 4-

stage decanting system to effectively reduce water content (Counterspil Research, 

2011)

Clamshell dredges Successful when oil solidifies (Counterspil Research, 2011)

ROVs and mini-subs Potential to recover oil from greater depths

Marine Pollution Control has been testing a mini submarine mounted with a 

suction recovery system (Counterspil Research, 2011)

Nets Messy and largely ineffective (Counterspil Research, 2011)

Dredging Effective

Generally limited to 50 meters water depth

Pneumatic dredgers can operate in greater depths

Fastest method of recovering sunken oil but generates a large volume of sediment 

and water that needs to be stored

Also need to consider the benefits of removing oil against seabed disturbance 

(Counterspil Research, 2011)

Based on the current state of recovery technologies, five problem areas need to be 

refined and addressed for heavy oil or oil sands products cleanup (Counterspil Research, 

2011):

1. Nozzle design of hoses to reduce the water intake during underwater pumping;

2. Diver-directed vacuum systems to increase the pumping rate;

3. Remotely-operated vehicles (not divers) development for safe pumping;

4. Dredges modified to minimize water and sediment uptake; and

5. Improvement in oil separation and water decanting technology. 

7.3.2.4 Transfer of Viscous Oil

Overall, the transfer of viscous oil should not be a limiting factor in heavy oil or oil 

sands products recovery. Many modifications to existing technology have already been 

made to process heavy oils (Counterspil Research, 2011). Table 7–5 summarizes potential 

transfer methods for recovered heavy oils.
88

Table 7-5. Summary of potential transfer methods for recovered heavy oils.

Technology Analysis

Pharos Marine GT185 

Skimmer

•

•

•

Main component of the Canadian Coast Guard recovery inventory.

Unable to recover and pump floating bitumen. Similar with USCG stock 

equipment, need modifications to process heavy oils (Michel, 2006; 

Counterspil Research, 2011)

Annular water injection Modified pump developed and tested in Denmark, Sweden, Norway, 

and Finland seems to be successful (Counterspil Research, 2011)

Key Sources: Effectiveness of Current Equipment on Sunken and 

Submerged Oil Spills

Counterspil Research. (2011). A Review of Countermeasures Technologies for Viscous Oils that Submerge.

Counterspil Research Inc. West Vancouver: Counterspil Research Inc.

Hansen, K. A., Fitzpatrick, M., Herring, P. R., & VanHaverbeke, M. (2009). Heavy Oil Detection (Prototypes) --

Final Report. United States Coast Guard, Research and Development Center. Washington, DC: U.S. 

Department of Homeland Security.

Michel, J. (2006). Assessment and recovery of submerged oil: Current state analysis. Research Planning, Inc. 

Groton: USCG.

7.3.3 Regional Response Capacity – Heavy Oil Spills

To obtain project approval from governing bodies, companies exploring, transporting, 

producing, and refining oils are required to submit a contingency plan in the event of a 

spill. The majority of oil companies choose to enlist an oil spill cooperative to satisfy oil 

spill response needs (Allen, 1981). The United States Coast Guard (USCG) does not have 

the equipment to respond to a submerged oil spill scenario (Hansen, 2013). Nationally, 

there are two oil spill cooperatives that have a large capacity for recovering heavy oil on 

the bottom of bodies of water: Marine Pollution Control (MPC), based in Detroit, Michigan, 

and BISSO Marine, based in Houston, Texas (Hansen, 2013). Other cooperatives do have 

capabilities including divers that can respond, or other special equipment used for 

recovery of oil inside vessels. 

Currently, there is no uniform method of reporting a region’s oil spill response 

equipment availability. As seen below, the Pacific Northwest and the New England areas 

aggregate their equipment lists into regional lists, which includes publically and privately 

owned equipment available in multiple states. The Great Lakes Region concentrates on 

equipment owned and operated by state governments.

In addition, many response organizations publish equipment lists, but they may not 

report all the necessary information to determine how the equipment can be used in an oil 
89

spill. For example, a response organization may report that it has a sonar in its inventory, 

but will not include the operational frequency or other vital processing information 

(Hansen, 2013). This complicates the assessment of a region’s capacity to respond to a 

heavy oil spill or a spill of oil sands products.

7.3.3.1 Response Capacity in Washington State

In the Pacific Northwest, all equipment maintained by spill response cooperatives in 

the area is listed at: http://www.wrrl.us. However, this list does not capture all the 

equipment that may be available to a responder during a spill because it only lists 

equipment that is geographically close to the spill. This means that oil spill response 

organizations outside of the Pacific Northwest that are contracted with oil companies 

operating in the region will not report available equipment to the WRRL. For example, 

Kinder Morgan theoretically could contract with BISSO, but because BISSO’s equipment is 

located in Texas, it is not accounted for in the WRRL.

The WRRL lists response equipment that is both dedicated to spill response and that

which is not. A substantial amount of the listed equipment is not necessarily dedicated to 

spill response. For example, WRRL includes a number of private fishing boats that could be 

used during a spill response effort. There is a possibility a listed piece of equipment may 

not be available during a spill (OSAC, 2009).

7.3.3.2 Response Capacity in the Great Lakes

Through various laws and regulations, the U.S. and Canada have a formal relationship 

in regards to oil spill preparedness and response programs. This is further elaborated in 

section 8.4.

The ability for response organizations to respond to a spill in the Great Lakes Region 

may be hindered significantly during winter conditions. With icy or snowy conditions, 

access to remote locations may be difficult and some facilities may operate with reduced 

personnel (Emergency Preparedness Task Force, 2012). The states in the region do not 

have a large inventory of response equipment (Emergency Preparedness Task Force, 

2012). For a full list of equipment available during a spill, broken down by state, see 

Appendix 4. 

7.3.3.3 Response Capacity in Maine

As part of Maine’s contingency planning, the Department of Environmental Protection 

created a directory of all spill response equipment located in the New England area. This 

includes oil response cooperatives, such as Marine Spill Response Corporation, U.S. and 

Canadian regulatory agencies, U.S. and Canadian Coast Guard contacts, and citizen 

volunteers who may choose to lend their boat or aircraft to spill response. This document 

can be found at: 

http://www.maine.gov/dep/spills/emergspillresp/documents/appendices.pdf. Again, this 
90

does not necessarily reflect the full response capacity of the region, as individual 

companies may contract with response organizations outside of the area.

Key Sources: Regional Response Capacity

Hansen, Kurt. (2013 11-February ). US Coast Guard. Personal Communication.

7.3.4 Information Gaps in Effectiveness of Current Equipment on Dilbit Spills

There are multiple gaps in policy and research in terms of equipment and mandated 

response capacity:

•

•

•

•

•

•

The regional and national equipment lists are missing key information about 

available oil spill response equipment capabilities, which makes it difficult to assess 

how a particular piece of equipment can be used effectively during a spill response 

scenario.

There is a lack of real world testing and experience with equipment on oil sands 

products spills, hindering our ability to assess whether or not a region has

equipment that will be effective in an oil sands products recovery effort.

When an oil spill occurs, the responsible party must respond within a specific period 

of time. If there is an oil sands products spill, the responsible party will be in 

compliance with oil spill response requirements as long as they have personnel on 

the site performing recover efforts, e.g. divers, not necessarily with the appropriate 

equipment to the specific type of oil spilled. This could mean that the responsible 

party would have to wait up to 72 hours for the appropriate equipment to reach the 

site if the spill is in Washington but the needed equipment is in Detroit or Houston.

Clean up regulations require response organizations to prove that they possess the 

equipment and can respond to a spill during a specified time period. However, 

policy does not require them to demonstrate the effectiveness of the equipment on 

specific oils. As we saw in the case studies, this may affect oil spill response

effectiveness. 

Material Safety Data Sheets (MSDS) (discussed further in Section 8.5.1) do not 

require the properties of the specific type of oil spilled to be noted. In the case of the 

Kalamazoo Spill, responders were given an MSDS that listed “crude oil” as the 

material spilled, not dilbit. This affected the responders’ ability to plan response 

efforts.

There is a lack of information and ability to employ oil spill detection and recovery 

methods when the oil reaches the bottom of a body of water or when the oil is 

suspended in the water column.
91

7.4 Introduction

Regulations and standards governing oil spills can largely be divided into two related 

categories—requirements for preparing for oil spills and requirements for responding to 

oil spills. The U.S. Coast Guard (USCG), the Environmental Protection Agency (EPA), and 

the Department of Transportation (DOT) oversee oil spill planning, response, and 

transportation—and are the primary regulatory actors for the transport of oil sands 

products. These regulatory categories can overlap, and are administered and enforced by 

multiple federal and state agencies. In this section, we outline:

•

•

•

•

Spill planning and response rules derived from the National Contingency Plan and 

the Oil Pollution Act;

The primary federal agencies responsible for rulemaking and enforcement in oil 

spill planning and response, noting any efforts to address the transport of oil sands 

products (focusing on the USCG, EPA, and DOT);

The role of states and regions in oil spill response planning, including some recent 

efforts to address the increase in oil sands products and additional legislation that 

could relate to oil sands products indirectly; and

Initial gaps in transportation and spill response and preparedness policies related to 

oil sands products.

7.5 Contingency Planning and Spill Response Background

In general, contingency plans are protocols detailing the steps responsible parties and 

government agencies must follow before, during, and after an oil spill and determine who 

should respond (EPA, 1999). The National Oil and Hazardous Substances Pollution 

Contingency Plan, commonly referred to as the National Contingency Plan (NCP), outlines 

the federal government’s procedures for oil spill contingency planning and response 

coordination (40 CFR 300). The NCP’s scope has been expanded several times since its 

original publication in 1968, with the most recent revisions in 1994 following the passing 

of the Oil Pollution Act (OPA). The NCP has created a multilayer National Response System 

for coordination of local, state, and federal agencies, industry, and other actors to ensure 

effective response to spills (EPA 2013). The NCP system is defined by a few key 

components (40 CFR 300):

•

•

•

National Response Team—established the NRT to plan and coordinate responses to 

major discharges of oil and to provide guidance to Regional Response Teams (RRTs)

Regional Response Team—established RRTs to coordinate, plan, and respond at the 

regional level and includes representatives from federal agencies that are members 

of NRTs plus local and state officials.

Federal On-Scene Coordinators (FOSCs)—established to coordinate federal efforts 

with local, state, and regional groups with four key responsibilities: assessment of a 
92

spill and resources needed, monitoring of responsible parties, federal response 

assistance if necessary, and evaluation of response actions overall.

• Unified Command—established a unified command structure to coordinate 

personnel and resources of federal and state officials as well as the responsible 

party.

For federal agencies this regulatory structure requires planning for coordination 

during oil spills and oversight of response plans. The regulatory framework for responding 

to a spill was solidified through the OPA amendments, which consolidated all federal spill 

response laws under one program (Ramseur 2012). The notable oil response provisions of 

the NCP include establishing (40 CFR 300.15):

•

•

•

•

•

The general responsibilities of FOSCs and authorizing FOSCs to direct response 

activities at spill site;

The general pattern of response of FOSCs in determining the threat, classification, 

size, and type of the release;

Authorization of FOSCs to determine if a spill poses a threat to public health or 

welfare;

Requirements of FOSCs to notify the National Strike Force Coordination Center 

(NSFCC)22 in the event of a worst-case discharges, defined as “the largest 

foreseeable discharge in adverse weather conditions;”

Provision of funding for oil spill responses under the Oil Spill Liability Trust Fund if 

certain criteria are met.

The NCP and OPA give responsibility for designating a FOSC to the EPA or the U.S. 

Coast Guard (USCG) depending on the location of the spill. USCG has the authority to 

“evaluate, coordinate and direct clean-up” of spills in coastal waters and the Great Lakes, 

and the EPA has the authority for inland spills (US Coast Guard Gulf Strike Team, 2008).

7.5.1 Discharge of Oil Regulation

The Discharge of Oil regulation, commonly known as the “sheen rule,” sets the 

standard for deciding whether or not a spill should be reported to the federal government 

(Discharge of Oil, 1996). Broadly, under the Clean Water Act, the sheen rule mandates that 

an oil spill should be reported if the spill poses a threat to public health or U.S. welfare. The 

rule specifically states that any spills with the following characteristics should be reported:

22 According to the USCG website, “the National Strike Force (NSF) provides highly trained, experienced personnel and 

specialized equipment to Coast Guard and other federal agencies to facilitate preparedness for and response to oil and 

hazardous substance pollution incidents in order to protect public health and the environment... The NSFCC provides 

support and standardization guidance to the Atlantic Strike Team (AST), Gulf Strike Team (GST) and Pacific Strike Team 

(PST).” 

 
93

1. Spills resulting in a discoloration or a sheen on the surface of a body of water;

2. Spills that violate pertinent water quality standards;

3. Spills that cause sludge or emulsion to be deposited beneath the surface of the water 

or on adjoining shorelines.

7.6 Federal Contingency Planning

The NCP framework has resulted in a web of federal agency responsibilities related to 

contingency planning and response requirements. This section outlines the main federal 

agencies that lead contingency planning: the USCG for vessels, the EPA for non-transportrelated inland spills, and the DOT in rail and pipeline transportation. We then discuss the 

role of regional and state plans and other potentially relevant laws governing increased 

transport of oil sands products. Throughout, we discuss if and how agencies have 

considered the transportation of oil sands products.

Oil spill prevention planning requirements are determined by the potential source of 

the spill, which for oil sands products primarily includes vessel, facility, pipeline, and rail. 

The USCG, EPA, and DOT play the most important role in establishing and implementing 

spill response procedures for operators. The designated federal agency must assess the 

capacity of the responsible party to effectively respond to a spill, which may include 

providing oversight of response plans, maintaining contingency plans at various levels, and 

personnel training (Ramseur 2012).

7.6.1 USCG

The USCG plays a key role in both spill response and clean up, and in spill prevention 

and preparedness. As the FOSC for maritime oil spills, the USCG is given the authority to 

ensure an effective response to oil spills in U.S. waters subject to the tide, the Great Lakes, 

and other specified waters (40 CFR 300.5).23 USCG jurisdiction in oil spill preparation and 

planning covers vessels, onshore facilitates with transportation-related activities, and 

deepwater ports (Ramseur 2008). Contingency plans for maritime oil spills in the U.S. are 

established at the national and regional level to ensure that for oil transported through 

Canadian waters, the U.S. is prepared to engage in cleanup if a spill has the potential to 

cross into U.S. waters or affect U.S. coastlines.

Under OPA and an international treaty, MARPOL 73/7824, owners and operators of 

vessels carrying oil must submit Shipboard Oil Pollution Plans (SOPEP) to ensure tanker 

crews have a plan to respond to an array of oil spill scenarios (Ramseur 2008). Annex 1, 

23 40 CFR 300.5 provides a full definition of coastal zone as: “all United States waters subject to the tide, United States 

waters of the Great Lakes, specified ports and harbors on inland rivers, waters of the contiguous zone, other waters of the 

high seas subject to the NCP, and the land surface or land substrata, ground waters, and ambient air proximal to those 

waters.”

24 MARPOL 73/78’s full name is the International Convention for the Prevention of Pollution From Ships, created in the 

years 1973 and 1978.

 
94

Regulation 37 of MARPOL requires that oil tankers weighing 150 tons gross tonnage or 

more carry an approved SOPEP (IMO 2013). Although other vessels are required to carry 

SOPEPs depending on tonnage (400 tons gross or more), oil tankers have specific plans 

given the large quantities of oil they hold. For U.S. ships, 33 CFR 151.27 requires the Coast 

Guard to ‘review and approve’ a vessel plan (USCG 1995). Among other things, a SOPEP 

contains:

•

•

•

•

•

•

General information about the ship,

Procedures to contain a discharge of oil,

Reporting procedures in case of a spill,

Drawings of fuel lines,

Descriptions and locations of oil tanks, and

Action plans for all crewmembers at the time of a spill.

A list of the vessel contents are also required, but in the case of vessels carrying oil 

sands products above an API of 10, a SOPEP would only be required to list “crude oil” 

instead of the specific product (see section 8.3.4 on Group V oils).

An update to the USCG’s FRP requirements went into effect in February 2011.

Aimed at improving response preparedness for facilities carrying or handling oil on U.S. 

navigable waters, the new regulation updated requirements for oil-spill removal 

equipment, added requirements for plan holders to use new response technologies, and 

amended procedures for spill response. The new rule applies to facilities already required 

to hold response plans under the FRP rules (Removal Equipment Requirements and 

Alternative Technology Revisions, 2009).

7.6.2 USEPA

EPA’s main responsibility relevant to oil spills is its responsibility as FOSC for inland 

oil spills, but it also regulates non-transport related spill planning. EPA provides oversight 

over Facility Response Plans (FRP), which are required under OPA. A FRP is required for 

certain facilities that store and use oil and include detailed plans for responding to a worst 

case discharge. As appropriate, FRPs also outline responses to small and medium 

discharges. The EPA has created regulations for what facilities must prepare and submit 

FRPs and what the plans must contain (US EPA, 2002).

OPA requires that “substantial harm” facilities develop FRPs. These include facilities 

that could cause substantial harm to the environment or navigable waters if a discharge

occurred. The specific regulation on “substantial harm” criteria is found in 40 CFR 112.20 

and 112.21, appendices B through F. Under the rule, a facility falls in the category if it 

meets at least one of the following criteria (Facility Response Plans, 2005):

• The facility has a total oil storage capacity greater than or equal to 42,000 gallons 

and performs overwater oil transfers to or from vessels; or
95

• The facility has a total oil storage capacity greater than or equal to one million 

gallons, and meets one of the following conditions:

•

•

•

•

The facility does not have secondary containment for each aboveground storage 

area; or

The facility is located such that a discharge could cause injury to an 

environmentally sensitive area; or

The facility is located such that a discharge would shut down a public drinking 

water intake; or

The facility has had, in the past five years, a reportable spill greater than or equal 

to 10,000 gallons.

7.6.3 DOT: Pipelines (PHMSA) and Rail (FRA)

The DOT houses two agencies that oversee the transportation of oil via pipeline and 

rail—the Pipelines and Hazardous Materials Safety Administration (PHMSA) and the 

Federal Railroad Administration (FRA). Pipeline transport of oil is heavily regulated 

beginning with pipeline siting, construction, and maintenance and continuing during the 

planning for potential oil spills and recovery efforts. Regulations for rail transport of oil are 

less robust. With increased transport of oil sands products from Alberta and crude from 

the Bakken region of western North America, review of rail transport oversight may be 

prudent. 

7.6.3.1 Regulating Oil Transportation by Pipeline

The Natural Gas Pipeline Safety Act of 1968 and the Hazardous Liquid Pipeline Act of 

1979 established the DOT as the federal agency responsible for oversight of pipeline safety 

in the U.S (Parfomak 2013). The Clean Water Act (as amended by the Oil Pollution Act of 

1990) requires regulations that establish oil spill planning requirements, plan review, and 

plan approval. I n 1991, Executive Order 12777 ordered PHMSA to develop regulations that 

require operators to submit spill response plans and review and approve plans for onshore 

pipelines (PHMSA 2012). PHMSA’s Office of Pipeline Safety now oversees these two 

primary regulatory areas, along with safety regulations of the design, construction, and 

maintenance of pipelines (49 CFR Part 195), and response plans for onshore oil pipeline 

spill response plan requirements (49 CFR Part 194).

Safety

The 1994 Pipeline Safety Act combined the two previous pipeline safety statutes, 

giving PHMSA authority to maintain the safe and reliable operation of the Nation’s pipeline 

infrastructure. The Office of Pipeline Safety developed prescriptive regulations for pipeline 

design, inspection in the manufacturing and construction processes, and maintenance and 

operation oversight through the life of the pipeline. Tools for enforcement included 
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warning letters and compliance orders followed by civil penalties—which are used 

alongside various information-sharing programs (PHMSA 2012a).

The prescriptive regulations before legislation in the early 2000s largely followed an 

inspection checklist approach. Accidents led to additional prescriptive requirements and 

also the inclusion of management-based mandates to analyze risk, identify spill prevention 

options and evaluate programs. The Pipeline Safety Improvement Act of 2002 established 

requirements for risk analysis and integrity management (IM) programs for operators 

(Parfomak 2013). Called the Liquid IM Rule, the program outlined how operators should 

‘identify, prioritize, assess, evaluate, repair, and validate the integrity of hazardous liquid 

pipelines that could, in the event of a leak or failure, affect High Consequence Areas (HCAs) 

with the United States” (PHMSA 2012b). The rules defined HCAs as population centers, 

ecologically sensitive areas, and commercially navigable waters—and required operators 

to explore how pipeline risks would impact HCAs.25 Finally, The Pipeline Inspection, 

Protection, Enforcement, and Safety Act of 2006 developed rules on corrosion, public 

awareness, and qualifications for operators and rules on pipeline control room 

management (Parfomak 2013).

Spill Response

PHMSA reviews contingency plans for pipelines where a major leak could cause harm 

to the environment. Requirements for an onshore pipeline spill response plan must 

(PHMSA 2012a):

•

•

•

•

•

Maintain consistency with National and Area Contingency Plans;

Identify the qualified individual (QI) with authority to respond; 

Identify private personnel and equipment necessary to remove a worst case 

discharge—and ensure their availability;

Describe training, testing, drills; and

Be updated periodically and after major changes.

PHMSA and Oil Sands Products

A number of recent events have led to changes at PHMSA that are directly or 

indirectly relevant to the transportation of oil sands products. The Enbridge spill on the 

Kalamazoo River and other pipeline accidents led to The Pipeline Safety Act in late 2011.26 

The legislation had a number of relevant components. First, it increased civil penalty 

authority for PHMSA for safety and compliance violations. Second, it required DOT to 

evaluate areas of technology that could increase safety and detect leaks and required 

PHMSA to evaluate if integrity management requirements should be expanded to more 

25 Full name: “Liquid Pipeline Integrity Management in High Consequence Areas for Hazardous Liquid Operators” found in 

49 CFR Parts 195.450 and 195.452

26 Full name: The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. See www.gpo.gov for the full text.

 
97

areas. Finally, it led to a study by the Transportation Research Board of the National 

Academy of Sciences to determine if regulations are sufficient for facilities transporting 

dilbit (Parfomak 2013). The study was tasked to analyze:

1. Dilbit risks to pipelines; does transport of dilbit increase the frequency of spills 

compared with other liquid petroleum products? and

2. If the committee finds that dilbit presents an increased risk, are current rules are 

sufficient to address the risk? 

The Transportation Research Board of the National Academy released its findings on 

25 June, 2013. The central findings were that the committee did not find any causes of 

pipeline failure unique to the transportation of diluted bitumen and did not find evidence 

of chemical or physical properties of diluted bitumen outside the range of other crude oils 

or any other aspect of its transportation by transmission pipeline that would make diluted 

bitumen more likely than other crude oils to cause releases. Upon release of the report, 

non-governmental organizations, including the Pipeline Safety Trust, a public interest 

group focusing on pipeline safety issues, criticized the scope for the report as too narrow

because it examined only the probabilities of an incident and not the consequences 

(Pipeline Safety Trust, 2013). PHMSA responded that it had expressly followed its mandate 

from Congress to commission a study that focused on comparative risk of spills from 

pipeline transport (Frosch, 2013).

Additional changes at PHMSA have resulted from recent spills (PHMSA 2012a):

•

•

•

•

•

More staff are now dedicated to plan-reviewing;

The Office of Pipeline Safety (OPS) initiated an internal audit of plan review 

activities;

PHMSA continues to revise its plan review criteria and procedures. Previously, only 

the response plan preparer was involved in the review process whereas now 

PHMSA includes operator compliance official(s) into reviews;

During the review process, an operator’s history is now considered. This includes 

incident and accident history; and

Increased participation in drills by operators.

Moving forward, PHMSA’s strategic plan is to integrate OPS, target and expand safety 

inspections based on the most serious risks, and focus pipeline safety research on methods 

to identify defects.27 In addition, PHMSA is also planning to review NTSB’s findings and 

recommendations on response plans, examine opportunities for better alignment with EPA 

27 Also see PHMSA Onshore Oil Pipeline Fact Sheet

http://www.eaovt.org/sbcap/pdf/FS19PipelineTransfer.pdf

 
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and USCG plan standards, and integrate spill plan responsibilities and the Pipeline Safety 

Inspection Program (PHMSA 2012b).

7.6.3.2 Regulating Oil Transportation by Rail

The boom in rail transportation of oil in Canada and the U.S. due to increases of the

supply in Alberta and the recent bonanza in the Bakken fields of the western U.S. has 

increased concern over the adequacy of regulatory oversight in rail transport. The Federal 

Railroad Safety Act of 1970 established the Federal Railroad Administration’s (FRA) role in 

overseeing the safety of rail transport in general, including the safe transport of hazardous 

materials (GAO 1998). Under 49 CFR 130, the FRA is required to oversee contingency 

plans for operators carrying ‘any liquid petroleum oil in a packaging having a capacity of 

3,500 gallons or more.” Response plans must follow the general pattern dictated by the 

NCP; operators must:

•

•

•

•

Outline the response procedure for potential discharges,

Consider the maximum potential discharge, 

Identify ‘private personnel and equipment available to respond to a discharge’, and

Identify relevant agencies to be contacted.

The FRA regulates safety in railcar construction and inspections of rail cars are 

required by DOT before loading operations begin and again once the car has been loaded. 

According to the EPA’s rules, railroad cars often present an issue of jurisdiction between 

DOT and EPA:

“DOT regulates railroad cars from the time the oil is offered for transportation to a 

carrier until the time that it reaches its destination and is accepted by the consignee. 

DOT jurisdiction includes railroad cars that are passing through a facility or are 

temporarily stopped on a normal route. EPA regulates railroad cars after the 

transportation process ends; that is, when the railroad cars are serving as nontransportation-related storage at an SPCC-regulated facility (EPA 2005).”

In addition, the USCG has regulatory involvement relative to transfers of oil from rail 

to barges and vice versa.

Due to the historical paucity of large-scale oil transport by rail, the Federal Railroad 

Administration, unlike PHMSA’s Office of Pipeline Safety, has no known program to 

specifically address potential spills of crude oil let alone heavy oils or oil sands products. 

With expected substantial increases in rail transport throughout North America and the 

many waterways along rail routes, increased oversight of planning and response to oil 

spills from train transport will likely be considered. The recent rail disaster in LacMégantic, Quebec, will likely focus regulatory scrutiny in both the U.S. and Canada on the 

adequacy of railroad contingency planning for oil-related incidents.
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7.6.4 Federal Planning Regulations Specific to Group V Oils

At least three federal contingency planning regulations apply specifically to Group V 

oils, two of which are of particular interest: 40 CFR 112 Appendix E, an appendix to the 

EPA’s oil pollution prevention plans, and 33 CFR Section 155.1052, USCG vessel 

requirements under the FCP.

1. 40 CFR 112 Appendix E—sets standards for facility owners or operators dealing with 

Group V Oils. Owners or operators must have contractual agreements that confirm 

access to response resources, including things such as sonar and oil locating 

sampling equipment. Notably, these resources “shall be capable of being deployed 

(on site) within 24 hours of discovery of a discharge” (Determination and 

Evaluation of Required Response Resources for Facility Response Plans, 2011).

2. 33 CFR Section 155.1052—sets ‘response plan development and evaluation criteria 

for vessels carrying group V petroleum oil as a primary cargo.’ Owners and 

operators of vessels must include specific information about the availability of 

equipment for response ‘capable of operating in the conditions expected in the 

geographic area(s) in which the vessel operates.’

These regulations, as well as contingency plan requirements in the state of 

Washington, require operators to plan specifically for carrying group V oils as a primary 

cargo. These regulations do not apply to oil sands products (normally classified as group IV 

when a diluent is used) even though they have the potential to be non-floating oils when 

spilled.

7.7 Regional and State Roles in Contingency Planning and Response

7.7.1 Plans for U.S.-Canada Contingent Waters

The Canada-U.S. Joint Marine Pollution Contingency Plan (JCP) is the coordinated 

system to plan, prepare, and respond to spills of oil and other harmful substances in 

contiguous waters of the U.S. and Canada. The JCP supersedes previous joint contingency 

plans and maintains consistency with provisions of Article 10 of the 1990 International 

Convention on Oil Pollution Preparedness, Response, and Co-operation and Annex 9 of the 

1972 Agreement between Government of Canada and the Government of the United States on 

Great Lakes Water Quality. The principle purpose of the JCP is to establish a coordinated 

system for planning, preparedness, and response to “incidents” of “harmful substances” in 

contiguous waters by supplementing existing national plans and ensuring cooperative 

bilateral response planning at the local and national levels (Canada-United State Joint 

Marine Pollution Contingency Plan, 2003). The JCP also facilitates the coordination of 

response activities for the parties responsible for a spill and establishes consultation 

procedures between parties responding to a spill.
100

Additionally, the JCP includes geographic annexes for five regions to better coordinate 

localized response efforts. Each geographic annex, referred to as a bilateral plan, serves to 

strengthen and coordinate the pollution response systems in order to facilitate an efficient 

cross-border spill response. Each geographic annex defines the roles of that region’s 

response team and is tested and updated through ongoing exercises. These five geographic 

annexes, each of which is pertinent to the transportation of oil sands products are as 

follows:

•

•

•

•

CANUSLANT: joint pollution response for Atlantic marine boundary between Canada 

and the U.S. This includes the Gulf of Maine and the Bay of Fundy. Relevant due to 

the potential of oil sands products passing through Portland, Maine.

CANUSLAK: joint pollution response for Great Lakes boundary between Canada and 

the U.S. Relevant due to oil sands products passing through the region via pipeline 

and rail, as seen in the Kalamazoo spill in 2010.

CANUSPAC: joint pollution response for Pacific water boundaries between Canada 

and the U.S. Relevant due to oil sands products passing through the Strait of Juan de 

Fuca region.

CANUSDIX: joint pollution response for Dixon Entrance water boundary between 

Alaska and British Columbia. Relevant due to potential for oil sands products to be 

transported to Valdez, Alaska via rail.

7.7.2 Regional Contingency Planning

Contingency plans specifically targeted for specific U.S. regions include USCG area 

contingency plans and the region-specific joint plans with Canada. In addition to the NCP 

discussed above, OPA requires that area committees are established by region as 

designated by the President of the United States. Area committees are composed of federal 

and state agencies that coordinate response actions with the private sector, local 

governments, and tribal communities. Federal On-Scene Coordinators in each area direct 

the committees, which are primarily tasked with developing Area Contingency Plans 

(ACPs), and work with responders to develop procedures to increase the efficiency of 

decision making for response actions. RRTs, as established in the NCP, are responsible for 

regional planning and preparedness prior to a response and each of the 13 RRTs maintain a 

Regional Contingency Plan. During a response, RRTs in each region support FOSC and State

On-Scene Coordinators (SOSCs). The principal purposes of ACPs in an oil spill are to:

1. Detail orderly and effective response actions to protect human health, property, and

natural resources; 

2. Promote the coordination and strategy for a unified response from federal, state, 

tribal, local, responsible party, and community actors; and
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3. Provide guidance for facility and vessel response planners (Northwest Area 

Contingency Plan, 2013).

As it relates to the transport of Alberta oil sands products, the following provides a 

brief overview and links to more information on ACPs in the Pacific Northwest, the Great 

Lakes Area, the area encompassing Maine, and Alaska. The RRTs that operate in 

coordination for these regions are:

•

•

•

•

Northwest: RRT, Region 10

Maine: RRT, Region 1

Great Lakes: RRT, Region 5

Alaska: RRT Alaska

7.7.2.1 The Northwest Regional Contingency Planning

The Northwest Area Contingency Plan (NWACP) covers the coastal and inland zones 

of Idaho, Oregon, and Washington. Regarding the ports and coastal waters surrounding 

Washington State in particular, the NWACP serves as the state’s Oil and Hazardous 

Substance Spill Prevention and Response Plan and applies to all public agencies that 

manage oil and hazardous substance spills. The Washington State Department of Ecology 

is Washington’s lead agency in overseeing the response, containment, and cleanup of oil 

spills in state waters.

In December 2012, the Washington State Department of Ecology added a new 

provision to the Oil Spill Contingency Plan requiring more detail on the type of oil handled 

to be included in a Material Safety Data Sheet (MSDS) or SOPEP. This new rule requires 

that responsible parties disclose the name of all oils handled on vessels and at facilities 

including pipelines as well as the density, gravity, API, oil group number, and sulfur content 

(Oil Spill Contingency Plan, 2012).28

Regarding non-floating oils, a Washington State standard effective January, 2013 

requires those plan holders that are “carrying, handling, storing, or transporting” Group V 

Oils to hold contracts with primary response contractors (PRCs) that “maintain the 

resources and/or capabilities necessary to response to a spill of Group 5 Oils.” This 

includes sonar, sampling equipment to locate suspended oil, and dredges, among other 

pieces of cleanup and detection equipment (Planning standards for Group 5 Oils, 2013).

Also notable in the Northwest region is legislation requiring the USCG to conduct a 

risk assessment regarding the transportation of Canadian oil sands products. Established 

via H.R. 2838, the Coast Guard and Maritime Transportation Act of 2012 requires the USCG 

to “assess the increased vessel traffic in the Salish Sea (including Puget Sound, the Strait of 

Georgia, Haro Strait, Rosario Strait, and the Strait of Juan de Fuca), that may occur from the 

28 NWACP website: http://www.rrt10nwac.com/

 
102

transport of Canadian oil sands products (Coast Guard and Maritime Transportation Act of 

2012, 2012).

29 More specifically, the assessment must identify:

•

•

•

•

•

The extent to which vessels traffic (for barge, tanker, and supertanker) will increase 

due to the development of Canadian oil sands products; 

Whether or not transport from the Canadian oil sands products will require 

navigation through U.S. territorial water; 

The regulations that restrict supertanker traffic and the amount of oil that tankers 

and barges can transport in U.S. waters as well as whether there are ways to bypass 

these rules ; 

The spill response capability throughout shared U.S. and Canadian waters including 

spill response requirements for vessels transiting through the waters of the other 

nation; and

Whether oil sands products have different properties from other types of oil, 

including toxicity and other properties, that may require different maritime clean up 

technologies. 

7.7.2.2 Maine

In the Northeast region, there is an ACP covering Maine and New Hampshire as well 

as a Maine Department of Environmental Protection (DEP) Marine Oil Spill Contingency 

Plan. The Maine and New Hampshire ACP was last updated in 2010. Maine law requires 

DEP to set up a state-specific Marine Oil Spill Contingency Plan to coordinate Maine’s 

response to oil spills. The DEP plan focuses on prevention, preparedness, timely response, 

and restoration and disposal. Recognizing the development of other contingency plans that 

apply to Maine, DEP affirms that the Marine Oil Spill Contingency Plan does not supersede 

any other plan and is intended to be carried out in coordination with other contingency 

plans (Maine DEP, 2011).30

7.7.2.3 Great Lakes

For the Great Lakes region, there is series of ACPs and Subarea Contingency Plans 

(SCPs) that cover the Eastern Great Lakes and Lake Michigan. These include the EPA 

Region 5 Regional Contingency Plan, the Eastern Great Lakes Area Contingency Plan, and 

the Sector Lake Michigan Area Contingency Plan.31

29 The bill can be accessed here (section 722) http://www.govtrack.us/congress/bills/112/hr2838/text/eah 

30 EPA Region 1 RRT website: http://www.rrt1.nrt.org/production/NRT/RRT1.nsf/AllPages/rrt1.html

Maine DEP Contingency Plan: http://www.maine.gov/dep/spills/emergspillresp/documents/contplan.pdf 

31 Great Lakes RRT website: http://www.rrt5.org/acp/ 

 
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7.7.2.4 Alaska

In addition to the Alaska-specific RRT, the state has a State Preparedness Plan for 

Response to Oil and Hazardous Substance Discharges/Releases (the Unified Plan) as well as 

ten SCPs. These SCPs, in coordination with the Unified Plan, describe the federal, state, and 

local response strategies for oil spills. The SCP most pertinent to the transportation of oil 

sands products is the Prince William Sound Subarea Contingency Plan for Oil and 

Hazardous Substance because of its inclusion of the waters and coastlines near Valdez, a 

possible terminal for dilbit carrying trains. This plan contains guidelines for operations in 

the event of an oil spill or discharge of other hazardous material.32

7.8 OSHA: Spill Response Planning Safety

In addition to the contingency plans coordinated with EPA, USCG, state agencies, and 

PHMSA, at national and sub-national levels, the Occupational Safety and Health 

Administration (OSHA) also participates in oil spill planning and response. In an effort to 

protect workers in a spill response scenario, OSHA focuses on exposure to toxic chemicals, 

training, job-specific safety hazards, heat stress, injuries, and illnesses. In order to assess 

worker exposure and safety, OSHA has set sampling strategies in place to monitor for air 

pollutants and respond with protective equipment as necessary (OSHA). In order for OSHA 

to effectively respond to a dilbit spill, it will be critical that the characteristics of the 

bitumen and the diluents be readily available.33

7.8.1 Material Safety Data Sheets (MSDS)

The IMO requires that vessels carrying oil or oil fuel have a MSDS prior to loading, 

similar to the contents disclosure required in SOPEPs. An MSDS requires the disclosure of 

“general categories of materials” that would be considered hazardous in the case of 

exposure, but does not specify the specific type of material (International Maritime 

Organization, 2009). MSDSs are required by a 2009 amendment to The International 

Convention for the Safety of Life at Sea (SOLAS) and are also required under the OSHSA 

Hazard Communications Standard in title III of the 1986 Superfund Amendments and 

Reauthorization Act (SARA). An MSDS for a vessel carrying oil sands products would list 

“crude oil” on the sheet and would not have to specify the type of crude.

7.9 Liability

OPA unified oil spill liability statutes hold the responsible party liable for any 

discharge of oil from a vessel or facility and all cleanup costs incurred by government 

entities, private parties, injury to natural resources, and loss of personal property. 

32 Alaska RRT website: http://alaskarrt.org/

Prince William Sound Subarea Contingency Plan website: http://dec.alaska.gov/spar/perp/plans/scp_pws.htm 

33 OSHA Oil Spill website: http://www.osha.gov/oilspills/index.html 

 
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7.9.1 USCG National Pollutions Funds Center and the Oil Spill Liability and Trust Fund

Related to the liability issue, Title I of OPA authorized the Oil Spill Liability and Trust 

Fund (OSLTF). OSLTF makes available up to $1billion per incident to assist the responsible 

party in oil removal and otherwise uncompensated damages (USCG 2013). Administration 

of OSLTF, handled by the USCG National Pollution Funds Center (NPFC), ensures funding 

for a federal response to oil spills and recovers costs from liable parties. The NPFC was 

established specifically in 1991 with a mandate of implementing Title I of OPA and is 

committed to protecting the U.S. environment through certifying that oil-carrying vessels 

have the financial capacity to contribute in the case of a spill.

The OSLTF is split into two major components: the Emergency Fund for response to 

oil discharges and initial natural resource damage assessment and the Principal Fund to 

pay claims and fund appropriations by Congress that administer OPA provisions and 

support research and development. The Principal Fund has five sources of revenue, the 

largest of which is an eight-cent-per-barrel excise tax collected from the oil industry on 

petroleum imported to or produced in the United States. Notably, as a result of an Internal 

Revenue Services (IRS) exemption, dilbit and synthetic crude derived from oil sands are 

exempt from paying this barrel tax, although spills of oil sands products are covered by the 

OSLTF (IRS, 2011). See policy gaps section below for further information on the 

exemption.

Ensuring responsible parties have the funds to be held accountable, the NPFC issues 

Certificates of Financial Responsibility (COFR), which demonstrates that vessels can pay for 

damage and cleanup up to OPA’s required liability limits. With few exceptions, vessels 

weighing more than 300 gross tons must have a valid COFR before navigating U.S. 

waterways. The NPFC also recovers costs from responsible parties, provides quick 

response funding, and compensates claimants for costs and damages (US Coast Guard, 

2012).

7.10 Other Pertinent Regulations

In addition to the policies and regulations discussed above, three additional federal 

regulations are pertinent to the transport and discharge of bitumen and dilbit. These 

include the Fish and Wildlife Coordination Act, Marine Mammal Protection Act, and the 

Endangered Species Act.

7.10.1 Fish and Wildlife Coordination Act (FWCA)

Intended to minimize the adverse impact on fish and wildlife resources and habitat, 

the FWCA requires federal agencies to consult with the US Fish and Wildlife Service, the 

National Marine Fisheries Service, and State wildlife agencies for all activities that affect, 

control or modify any streams or bodies of water ((Fish and Wildlife Coordination Act). 

This consultation is generally incorporated into the permitting process or licensing 
105 

requirements required during the construction of pipelines that cross water bodies and for 

upgrades to shipping terminals.

7.10.2 Marine Mammals Protection Act

The Marine Mammals Protection Act (MMPA), enacted in 1972, serves to protect all 

marine mammals in U.S. waterways from harm, capture, and harassment. The act was 

passed due to several findings including the potential risk of extinction or depletion that 

some marine mammals may face as a result from human action, the fact that marine 

mammal species must not be permitted to fall below optimum levels for sustainable 

population, and the understanding that measures should be taken to replenish these 

species (Marine Mammal Protection Act, 1972). Given the rise in transportation through, 

over, and adjacent to U.S. waterways resulting from the oil sands industry, this act is 

important when considering transportation routes and measuring impacts to marine 

mammals and their support habitats. 

7.10.3 Endangered Species Act (ESA)

In an effort to conserve endangered and threatened species and their habitats, the 

ESA mandates that federal departments and agencies ensure that any authorized, funded, 

or implemented action is “not likely to jeopardize the continued existence of listed species 

or modify their critical habitat.” NOAA and USFWS are responsible for publishing lists of 

endangered and threatened species. The ESA would apply to the construction of dilbit 

transport infrastructure and must also be considered in spill planning and response 

activities (Endangered Species Act, 1973).

7.11 Policy Gaps and Analysis

The outline of regulations governing oil spills and their prevention above has 

suggested potential gaps in regulations when it comes to increased transport of oil sands

products. The two most obvious gaps are the exemption of oil sands products from an 

excise tax and the lack of specific information required by facilities and transporters 

regarding the oil product they are handling. However, there are additional gaps in policies 

and regulations that warrant attention as transport of oil sands products increases. The 

Federal Railroad Administration has not invested much time or effort for oversight of oil 

spill planning, as large oil spills in rail transport have not generally been a threat until 

recently, during which oil transport via rail has rapidly increased. Further, there is a 

concern that the recently drafted PHMSA contingency plans for pipelines are not wellintegrated with regional and area plans, as required. In addition, while many current 

regulations give agencies the authority to effectively regulate bitumen products, problems 

can arise from a lack of resources and experience dealing with unconventional oils.
106

7.11.1 Dilbit Excise Tax Exemption

An IRS memorandum exempted dilbit and synthetic crude derived from oil sands

from being subject to an eight-cent-per-barrel excise tax that would otherwise go into the 

Oil Spill Liability Trust Fund. The July 2011 IRS memorandum stated: “tar sands imported 

into the United States are not subject to the excise tax on petroleum imposed by § 4611 of 

the Internal Revenue Code” (IRS, 2011). Notably, this fund can be drawn upon to cover 

spills of oil sands products. “Tar Sands” in this context refers to two materials:

1. Dilbit: described in the memo as “bitumen extracted from tar sands and blended 

with a diluent or other liquid that enables the bitumen to be transported through a 

pipeline”

2. Synthetic Crude: described as “an upgraded oil stream which is a synthetic crude oil 

derived from tar sands.”

The exemption was made at the request of an anonymous company that was 

referenced only as “Company” in the IRS memorandum.34

7.11.2 Disclosing Oil Type and Characteristics

The majority of oil spill contingency plans do not require responsible parties to 

disclose specific information on the type of oil that could be handled in a spill. Further 

complicating matters, when regulations do require disclosure of oil types, oil sands or oil 

sands-derived products are not listed among the types of oils to disclose. For example, the 

Washington Department of Ecology adopted rules for transferring oil over water that 

require the delivering facility to submit an Advance Notice of Oil Transfer (ANT) 24 hours 

prior to transfer. In addition to other reporting requirements, the ANT must provide 

information on the oil product type and quantity (Advance Notice of Transfer, 2006). 

However the data available for reporting is based on the Puget Sound/British Columbia 

(PS/BC) Oil Spill Task Force data dictionary, which does not currently include oil sands 

products.

Regulators in Washington State are working to close these reporting gaps. 

Washington State passed a provision to the state’s Oil Spill Contingency Plan in 2012 

requiring responsible parties to provide the names and physical characteristics of all oils 

handled by vessels and facilities (Spill Contingency Plan, 2012). Given the unique 

characteristics of bitumen and dilbit, Washington can be considered as an early actor. 

Contingency plans, at the national, regional, and state level could build similar provisions 

into their contingency planning requirements.

34 Available online at: http://www.irs.gov/pub/irs-wd/1120019.pdf 

 
107

7.11.3 Planning for Response to Group V Oils

Linked to the matter of contingency planning and oil type disclosure, there is a 

concern that in certain scenarios oils sands products could have the characteristics of 

group V—or non-floating—oils. Oil sands-derived products are normally classified as 

group IV oils based on physical characteristics once blended with a diluent or a synthetic 

crude. The contingency planning requirements for group V oils outlined in section 8.3.4 

therefore do not apply to oil sands-derived products. However, as diluents weather after a 

dilbit spill or if unblended bitumen were to be transported via railcar as has been 

suggested, the material at the spill site could potentially be a non-floating oil. In failing to 

suggest that bitumen-products could potentially meet the characteristics of group V oils, 

contingency plans could be underestimating the risks and response needs in the case of a 

spill of oil sands products.

7.11.4 Assessing Risks of Transportation Oil Sands Products

As discussed above, a recent bill will require an assessment of the waterway 

transportation routes through the Salish Sea as they concern the Canadian oil sands 

products. This bill also requires an assessment to discern the different properties between 

Canadian oil sands products and other types of oil. There are not similar efforts underway 

to assess the risks of transporting Canadian oil sands products in East Coast and Gulf of 

Mexico waterways, across major river crossings, and near the Great Lakes via rail and 

pipeline.

7.11.5 Inconsistencies in Contingency Planning: PHMSA

Section 8.3.3 outlines the efforts that DOT and PHMSA have taken to better plan for 

the transport of oil sands products in light of the Michigan Enbridge pipeline spill. One of 

the requirements for PHMSA pipeline contingency plans is to ensure consistency with 

regional and national plans. However, a reported lack of coordination between RRTs and 

PHMSA raises the concern that the PHMSA plans are not integrated into regional and area 

plans and vice versa. The fact that RRTs might not have access to PHMSA plans and cannot 

integrate them accordingly into their plans, could result in inconsistencies between plans 

and a compromised response effort in the case of a spill. RRT 10 has reported a plan to 

draft a memorandum of understanding with PHMSA to gain access to pipeline contingency 

plans, which would potentially solve this problem and set an example for other RRTs as 

well as national planners (Chris Field personal communication, 2013). 

7.11.6 Increased Transport of Oil by Rail

The extremely rapid increase in the proportion of oil sands products and other oils 

transported by rail, and recent rail accidents involving petroleum products loaded onto 

railcars, have raised concerns that regulation of rail transport is inadequate for addressing 
108

the scale of activity and the growing risk factors. While the Department of Transportation 

regulations cover the basic contingency planning requirements, the intent and capabilities 

of the Federal Railroad Administration to oversee this dramatic increase in transport is 

unclear at the present. The Federal Railroad Administration, unlike PHMSA’s Office of 

Pipeline Safety, has no established program to address potential spills of crude oil, heavy 

oils or oil sands products.

Key Sources: Important Policies and Regulations

EPA, Office of Emergency and Remedial Response. (1999). Understanding oil spills and oil spill response.

PHMSA. (2012a). Oil Spill Response Plans: A History Lesson. PHMSA Presentation. Alan Mayberry. July 12, 

2012. 

Parfomak, Paul (2013). Keeping America’s Pipelines Safe and Secure: Key Issues for Congress. Congressional 

Research Service, Report R41536.

Ramseur, J. L. (2012). Oil Spills in U.S. Coastal Waters: Background and Governance. Congressional Research 

Service, Report RL33705.
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8 GAPS AND RECOMMENDATIONS

This section summarizes the gaps in information, research, and policy that we have 

uncovered throughout our research related to oil sands transport and oil spills in general. 

There are still many questions to be answered related to the risks associated with the 

transportation of oil sands products. Listed below are the main gaps that we have 

identified, as well as actions to address at least some of those gaps. 

8.1 Policy

Currently, only a limited number of policies exist that explicitly address the 

transportation of oil sands products in the U.S. Below are a number of areas where we find 

the lack of information to be potential concerns, categorized by planning, transportation, 

and response requirements:

8.1.1 Planning

Pipeline spill plans are not consistently integrated with the regional and area 

contingency planning process. Currently, EPA is charged with regulating area plans, 

while PHMSA is the ultimate authority on pipeline spill plans. Although PHMSA requires 

that pipeline contingency plans maintain consistency with area and regional spill response

plans, PHMSA’s role in spill planning varies from state to state, making it difficult to 

maintain consistent relationships with EPA and regional planning bodies such as the RRTs. 

As a result, in some regions, there are no agreements in place for PHMSA to consult and 

collaborate with EPA to ensure that pipeline spill plans are integrated and consistent with 

other regional plans. 

Recommendation: RRTs and PHMSA should cooperate to increase coordination of oil 

spill plans, particularly as they relate to oil sands products. The NRT should facilitate 

conversations at the federal level to promote national consistency and clarity with respect 

to the roles and obligations of agencies in spill response planning.

Companies transporting oil sands products are not subject to the eight-centper-barrel excise tax that supports the Oil Spill Liability Trust Fund. A spill of oil sands 

products would be eligible to be covered by the fund, fostering questions of equity (i.e., why 

are oil sands products not taxed if they are otherwise considered the same as other 

petroleum products?) and the long-term viability of the OSLTF, with the increasing 

prominence of oil sands in the domestic energy portfolio. 

Recommendation: The IRS definition of oil sands products as not petroleum should be 

reviewed. An oil sands product spill would require significant recovery efforts comparable 

to, if not exceeding, a spill of conventional crude that is subject to the tax. The scale and 

cost of the Kalamazoo River spill response and cleanup efforts support this assumption; in 

March, 2013, Enbridge warned investors that the continuing cleanup and additional 
110

dredging requirements by EPA may push its costs for the incident above the $1 billion level 

and beyond the limits of coverage for insurance (Cryderman, 2013).

Current pipeline operator preparedness and training requirements should be 

reviewed by federal pipeline regulators. As evidenced by the case studies discussed in 

this document, human error played a prominent role in most of the incidents showcased, 

resulting in more oil entering the environment than would have occurred if existing

protocols had been properly followed. This was especially apparent in pipeline operators’ 

inability to distinguish between false and real alarms, and the time delays involved in 

completely shutting down pipeline flow once anomalies were detected. 

Recommendation: Enbridge implemented a number of mandatory training exercises 

for its personnel after the Kalamazoo River spill that could be considered by other pipeline 

operators at regional and national levels. First, Enbridge increased the number of 

emergency response simulator sessions that operators were required to attend from one 

per year to two per year. Two additional training sessions were mandated that focused on

human factors that contribute to response failure and hydraulic issues. Additional training 

was also provided on column separation. More information on Enbridge actions can be

found in the NTSB (2010) report under section 1.14.3. 

Regulations do not require risk assessments related to water terminals until 

construction is taking place. Risk assessments are not required for terminals that are 

expected to handle oil sands products until upgrades to facilities are already underway.

Recommendation: Risk assessments should be considered for facilities construction 

plans before permits are granted, to ensure that new risks are appropriately considered, 

vetted, and factored into the decision to expand a terminal’s capacity.

8.1.2 Transportation

Rail regulations and spill preparedness for the rail transport of crude oil are 

unclear and not widely available. Although the FRA has plans in place to handle spills of 

hazardous materials, these do not directly address oil spills in general or oil sands products

in particular. FRA oversight and regulatory authorities related to petroleum products 

being transported by rail should be reviewed, clarified, and strengthened to reflect the 

growing scale of that mode of transportation in North America. 

Recommendation: Review the regulations and spill contingency plans for rail 

transport of petroleum products, especially for oil sands products. As with pipeline 

response plans, the rail plans should be integrated with other regional spill response plans 

that are overseen by the NRT and implemented by the RRTs. 

Current policies do not require pipeline operators, rail carriers or tank vessels 

to provide information on the specific type of oil product being transported in a 

pipeline, train or vessel. The lag time associated with regulatory and response agencies 

acquiring detailed cargo information from the shippers, pipeline and vessel operators, or 

rail carriers has affected response activities in past spills. Lack of detail also adversely 
111

impacts the ability of agencies and oil spill response organizations to effectively implement 

contingency planning in advance of spill incidents

Recommendation: The ability of pipeline, rail, and vessel operators to identify and 

track the types of oil present in each batch being transported should be improved and the 

means to communicate this information in an emergency codified; regulatory and response 

agencies should be permitted access to this information when a spill is reported. This will 

allow industry, regulatory, and response agencies to understand what product is spilled

when the response is initiated, and more effectively structure the response to address the 

specifics of petroleum/oil sands product involved. 

8.1.3 Response

Oil spill regulations require response organizations to demonstrate equipment 

deployment capabilities, but do not address testing or validation of equipment 

effectiveness for specific oils. If a spill of oil sands products occurs, the responsible party 

is in compliance with response requirements if a response effort has been implemented; 

but it is not necessary to have the appropriate equipment on site to address oils that may—

for example—submerge or sink over time. Initial response time with product-appropriate 

equipment could be especially critical for a spill of oil sands products, given the uncertainty 

of weathering effects and the increased potential for the oil to submerge over time. The 

Wabamun Lake spill demonstrated the importance of deploying appropriately trained and 

equipped responders to address product-specific challenges.

Recommendation: Contingency planning and spill response exercises should consider 

and incorporate oil spill scenarios involving oil sands products whose environmental 

behavior can change considerably with time. As noted below, equipment inventories 

should be re-evaluated and classified to indicate application to heavy, submerged, or 

sunken oil.

MSDSs currently do not describe the specific type of oil being transported. In 

the Kalamazoo River spill, the MSDS detailed that “crude oil” had been spilled, but did not 

specify that dilbit was the actual product in the pipeline. This affected the nature of the

response and resulted in additional public and environmental health concerns. In the 

Mayflower ExxonMobil Pipeline spill, it was not confirmed by the responsible party for 12 

days that the product spilled was in fact a diluted bitumen product and not, as initially 

described, a heavy crude oil.

Recommendation: Consider the Washington regulation discussed in Section 8.4.2.1 as 

a potential model for other regions. 

Response plans do not address the potential for oil sands products to act as 

non-floating oils in the case of spill. There is a concern that under certain conditions, oil 

sands products could have the characteristics of Group V—or non-floating—oils. However, 

the contingency planning requirements for Group V oils outlined in section 8.3.4 do not 

apply to oil sands products.
112

Recommendation: Regional and area response plans should reflect the fact that in the 

event of a spill of oil sands products, there is the potential for the material to sink or be 

suspended in the water column. Recognizing that equipment and capabilities to respond to 

submerged oil are currently limited, the primary value of inclusion in contingency plans 

would be for responder and resource manager awareness. However, this may change as 

new technologies are developed and adopted for Group V oil spill response.

Regional and national capacity to respond to an oil sands product spill is 

unclear, as most equipment lists do not provide information about applicability to 

different oil types. 

Recommendation: Expand the information listed by oil spill response organizations in 

equipment inventories to include basic performance information related to applicability to 

specific oil types. 

8.2 Research

In general, there is a lack of published, independent oil sands-related research. There 

are a number of studies underway, but the results have not been published and may not see 

wide distribution. Research is desirable in three categories: the physical properties and 

behavior of oil sands products; the increased risk associated with transporting oil sands 

products; and the effectiveness of current oil spill equipment for an oil sands products. For 

each grouping, we recommend independent research for the information gaps. Specifically:

8.2.1 Physical Properties & Behavior of Dilbit

The physical properties and behavior of the diluent component of oil sands 

mixtures, and the associated potential public health concerns have not been 

adequately addressed. The health risks for responders and exposed communities may 

differ depending on the diluent being used. There are gaps in data on the properties of

specific diluents, especially as components in bitumen mixtures, and—as alluded to 

above—shortcomings in labeling and MSDS requirements that do not distinguish between 

oil sands products and other petroleum products. Additional information on the 

environmental behaviors of different oil sands products mixtures is necessary to better 

characterize potential respiratory hazards to responders and the exposed public, and to 

gauge potential flash point risk from volatilized concentrations of diluents that may occur 

in areas of aggregated oil. 

There are uncertainties regarding how weathering affects the environmental 

fate and behavior of spilled oil sands products, particularly under differing 

conditions of salinity and temperature. That is, what are the conditions, if any, under 

which spilled oil sands products would be overwashed by water, suspended in the 

water column, or sunk. An important consideration for spill response is the timing 

associated with density changes, for example, how long could we reasonably expect a spill 

of oil sands products to largely remain on the surface under a given set of conditions?
113

Information regarding how oil sands products will biodegrade in the 

environment is lacking. Given that oil sands are already partially biodegraded, it is 

unclear what the implications are for the environmental fate of a spilled mixture. If it is a 

dilbit or a synbit, the biodegradation potential presumably depends on the diluent 

component. If the diluent rapidly volatilizes or is preferentially biodegraded, the remaining 

bitumen component may be relatively persistent and resistant to further degradation. This 

would influence potential use of bioremediation as a response tool, and would be a relevant 

consideration in “how clean is clean?” discussions as the end of active response is 

approached

When oil sands research is conducted, a variety of oil sands products should be 

tested. Bitumen properties vary both by deposit and over time within the same deposit. 

Diluents may differ substantially in their chemical composition and physical behavior, and 

because of the many permutations of transport mixtures possible, environmental fate and 

effects cannot be generalized from one or a few product samples.

8.2.2 Transportation Risks

The risks associated with increased waterborne transport of oil sands products 

are not well-defined. While there is at least one planned study assessing the risk 

associated with an increase of traffic through the Salish Sea in the Pacific Northwest, there

are no comparable studies (as of March 2013) that would examine risks related to potential 

increases in tanker or rail traffic in or near East Coast and Gulf of Mexico waterways, major 

river crossings, and the Great Lakes. There is a comprehensive vessel risk assessment 

planned for traffic through the Aleutian Islands that should factor the increased transport 

of oil sands products from west coast ports to Asia.

Recommendation: Consider risk assessments that include the increased traffic in the 

Aleutian Islands, East Coast and Gulf of Mexico waterways, major river crossings, the Great 

Lakes, and other waterways that could experience increased transportation of oil sands 

products. Each risk assessment should identify/isolate the additional risk contribution 

represented by regional increases in oil sands products transport.

8.2.3 Response Effectiveness

There is a lack of real-world testing and experience with recovery equipment 

on oil sands products. This impedes our ability to determine whether a region is 

prepared for an oil sands products spill, and which equipment will be effective.

Recommendation: Controlled experiments at meso-scale test facilities like USDOI’s 

OHMSETT facility in New Jersey evaluating current equipment effectiveness on oil sands 

products should be considered. A range of oil sands products should be used to test the 

equipment, including different product types (dilbit, synbit, synthetic crude, etc.) and 

different bitumen sources (Cold Lake, McKay River Heavy, etc.), as well as different 

ambient conditions (e.g., salinity, temperature, sediment load). 
114

Current capabilities to detect and recover oil when it sinks or is suspended in 

the water column are poor. 

Recommendation: Continue work in researching and developing new methods of 

detecting, monitoring, containing, and recovering sunken or submerged oil.

8.2.4 Other Gaps

Current LDS have not proven effective in alerting pipeline personnel to leaks 

and other issues. More research and development should be dedicated to improving the 

accuracy of LDS. Additionally, more and better-designed training may be necessary for 

pipeline operators to help them distinguish between real and false alarms. 

Some of the API values listed in this report are based on research completed in 

the 1980s. These values should be reviewed and as needed, updated and augmented to 

provide a more comprehensive knowledge base for modeling the environmental fate and 

behavior of oil sands products.
115

9 APPENDICES

9.1 Appendix 1: Oil Sands Major Players List

Individual/

Organization Description of Involvement Additional Information

Energy Companies

BP Canada Energy 

Trading Company

BP uses in situ extraction at three jointly owned 

mines: Sunrise oil sands (50% owner, Husky 

Energy operator); Pike oil sands (50% owner, 

Devon Energy operator); Terre de Grace oil 

sands (75% owner and operator). These 

projects have not begun producing yet, but the 

first is expected to go online in 2014. BP also 

signed a long-term contract with Kinder 

Morgan's (KM) Trans Mountain Pipeline and 

has both downstream and upstream facilities.

http://www.bp.com/sectiongeneri

carticle.do?categoryId=9036695&c

ontentId=7067648 

http://www.transmountain.com/n

ews-releases/trans-mountainupdates-customer-commitmentsfor-proposed-expansion-project 

Canadian Natural 

Resources

Canadian Natural Resources is the operator and 

owner of the Kirby, Grouse, and Primrose and 

Wolf Lake In Situ Oil Sands Projects. It also 

signed a long-term contract with KM's Trans 

Mountain Pipeline and is a strong supporter of 

the Enbridge Line 9 Reversal project.

http://www.cnrl.com/operations/

north-america/north-americancrude-oil-and-ngls/thermal-in situoilsands/

http://www.transmountain.com/n

ews-releases/trans-mountainupdates-customer-commitmentsfor-proposed-expansion-project

Cenovus Energy 

Inc.

Cenovus owns and operates two in situ 

extraction sites in Foster Creek and Christina 

Lake in conjunction with ConocoPhillips (50% 

share). It jointly owns two refineries in the U.S., 

with a 50% interest in ConocoPhillip's Wood 

River and Borger refineries. Cenovus signed a 

long-term contract with KM's Trans Mountain 

Pipeline.

http://www.cenovus.com/operati

ons/index.html

Chevron

Chevron jointly owns the Muskeg River Mine in 

Alberta which went online in 2011. Its current 

capacity is approximately 255,000 barrels per 

day (b/d).

http://www.chevron.com/deliveri

ngenergy/oilsands/
116

Individual/

Organization Description of Involvement Additional Information

China National 

Petroleum Corp. 

(parent company 

of Petro-China)

In 2007, CNPC was the first Chinese company to 

win mineral rights to mine bitumen. In August 

2009, CNPC bought 60% of the development 

rights of Athabasca Oil Sands Corp.'s Mackay 

River and Dover projects. In 2012, this was 

extended so that CNPC was the owner and 

operator of the MacKay River oil sands project. 

In 2005, the company signed a Memorandum of 

Understanding (MOU) with Enbridge 

supporting a western pipeline that would help 

carry crude to China via tankers (Northern 

Gateway). 

http://www.cnpc.com.cn/en/cnpc

worldwide/canada/

http://www.scmp.com/article/59

8721/cnpc-wins-right-work-oilsands-alberta

http://www.theglobeandmail.com

/news/politics/chinas-oil-sandsdeal-will-have-lastingimpact/article1357620/

Chinese National 

Offshore Oil 

Company (CNOOC)

CNOOC is a Chinese state owned multinational 

oil company that operates in Canada and the 

U.S. In July of 2012 CNOOC announced plans to 

buy Canadian oil firm Nexen for $15 billion. It 

was recently approved by the U.S. Committee of 

Foreign Investment (Nexen owns assets in the 

Gulf of Mexico) and the deal officially closed on 

2/25/2013. It also owns a 17% stake in MEG 

Energy, an Alberta oil sands project developer. 

In 2011, CNOOC acquired equity interest in 

OPTI, a Canadian oil sands producer.

http://www.cnoocltd.com/encnoo

cltd/AboutUs/zygzq/Overseas/13

2.shtml

http://www.cnbc.com/id/100454

779/CNOOCNexen_Deal_Wins_US_

Approval_Its_Last_Hurdle

http://business.financialpost.com/

2013/02/25/cnooc-completescontentious-15-1-billionacquisition-of-nexen/?__lsa=5f87-

ac2a

ConocoPhillips

ConocoPhillips holds approximately 1 million 

net acres of land in northeastern Alberta. Its 

main operations occur at the Surmont oil sands 

project, southeast of Fort McMurray where the 

company employs in situ extraction techniques. 

The Surmont project is a 50/50 joint venture 

project with Total E&P Canada Ltd and has the 

capacity to produce 110,000 b/d. 

ConocoPhillips is also in a 50/50 partnership 

with Cenovus Energy. This partnership 

operates the Foster Creek and Christina Lake 

projects as well as the proposed Narrows Lake 

project. The partnership has a total capacity of 

428,000 b/d. Most of its oil sands product is 

piped through the Keystone pipeline to U.S. 

refineries, specifically the Phillips 66 Wood 

River Refinery. 

http://www.conocophillips.com/E

N/oilsands/assets/Pages/index.as

px

http://www.conocophillips.com/E

N/oilsands/overview/Pages/trans

portation.aspx
117

Individual/

Organization Description of Involvement Additional Information

Exxon 

Mobil/Imperial Oil 

Ltd./Esso

ExxonMobil Canada and Imperial Oil jointly 

own the Kearl oil sands project, which is one of 

Canada's largest open-pit mining operations 

north of Fort McMurray. Its current capacity is 

345,000 b/d. The project is assessing its 

refining options and will most likely integrate 

with North American refineries owned by 

Imperial Oil and ExxonMobil. Enbridge's Line 

9A Reversal project was pursued due to a 

request from Imperial Oil. 

http://www.imperialoil.ca/Canada

-

English/operations_sands_kearl_ov

erview.aspx

http://www.enbridge.com/ECRAI/

Line9ReversalProject.aspx

Flint Hills 

Resources/Koch 

Industries

Flint Hills Resources, which is operated by Koch 

Industries, is an oil refinery company in the U.S. 

Its St. Paul, Minnesota refinery is rumored to be 

refining over 320,000 b/d of oil sands products. 

http://www.fhr.com/refining/cana

da.aspx

http://www.sustainablebusiness.c

om/index.cfm/go/news.display/id

/22112

Husky

Husky energy has been exploring oil sands 

since 1973 and is one of the top holders in oil 

sands reserves in Alberta. Its Sunrise reservoir 

alone is estimated to hold 3.7 billion barrels of 

bitumen as of 12/2011. It jointly owns a 

refinery near Toledo, Ohio. 

 

Marathon

Marathon Oil has a 20% share of the Muskeg 

River and Jackpine mine as well as the Scotford 

Upgrader. It also has the rights to over 216,000 

acres of potentially mineable land in the 

Alberta region. Marathon owns interests in in 

situ oil sands leases near Fort McMurray. It is 

also one of the largest oil refinery companies in 

the United States. 

http://www.marathonoil.com/Glo

bal_Operations/Canada/Operation

s/
118

Individual/

Organization Description of Involvement Additional Information

Nexen Marketing 

Inc.

Nexen has an interest in over 300,000 acres in 

the Athabasca region. It's the 65% owner and 

operator of the Long Lake reserve, where they 

use in situ extraction to produce synthetic 

crude on site. Nexen also has begun developing 

the Kinosis area and the extracted bitumen will 

be upgraded at Long Lake. It has a 7% interest 

in Syncrude's oil sands mining and upgrading 

facilities and has a 15% non-operating interest 

in Hangingstone, an extraction project 

developed by Japan Canada Oil Sands. Nexen 

signed a long-term contract with KM's Trans 

Mountain Pipeline. As mentioned before, Nexen 

was recently purchased by CNOOC. 

http://www.nexeninc.com/en/Ope

rations/OilSands/OurOilSandsBusi

nesses.aspx

PBF Energy

PBF Energy owns nearly 1/3 of U.S. East Coast 

refining capacity and is expected to refine oil 

sands products.

http://www.ubs.wallst.com/ubs/

mkt_story.asp?docKey=1329-

L1E8MQ61A-1&first=0

Shell Oil

Through Shell's Athabasca Project, where it is 

the majority owner (60%, with Chevron at 20% 

and Marathon at 20%), Shell both mines and 

upgrades bitumen and converts it to synthetic 

crude. It is the joint owner of two mines (the 

Muskeg River Mine and the Jackpine Mine) and 

the joint owner of one upgrader (Scotford 

Upgrader) in Alberta. It currently has the 

capacity to produce 255,000 b/d of synthetic 

crude. 

http://www.shell.com/global/abo

utshell/our-strategy/majorprojects-2/athabasca.html

SINOPEC

SINOPEC is a Chinese state owned company 

that bought a 9% stake in Alberta's Syncrude 

Canada Ltd. in 2010. It first became involved in 

Canadian oil sands in 2005 when it formed a 

joint venture with Canada-based Synenco 

Energy to form the Northern Lights oil sands 

project. SINOPEC continues to look for ways to 

grow its business in Canada. 

http://business.financialpost.com/

2012/12/12/sinopec-still-keen-toinvest-in-canada-as-long-astheres-money-to-bemade/?__lsa=5f87-ac2a

http://english.caixin.com/2010-

04-13/100134471.html

Statoil Canada Ltd.

Statoil uses in situ to extract bitumen from its 

Leismer Demonstration Project. It also signed a 

long-term contract with KM's Trans Mountain 

Pipeline.

http://www.statoil.com/en/enviro

nmentsociety/relevanttopics/oilsa

ndincanada/pages/default.aspx
119

Individual/

Organization Description of Involvement Additional Information

Suncor Energy 

Suncor was the original oil sands producer in 

the Athabasca region. It uses mining and in situ 

operations to extract bitumen and has two 

upgrading facilities on site in Fort McMurray 

and a third upgrader in Edmonton. Suncor has 

signed a long-term contract with KM's Trans 

Mountain Pipeline.

http://www.suncor.com/en/about

/242.aspx

Syncrude (Majority 

owner: Canadian 

Oil Sands, Ltd.)

Syncrude is one of the original oil sands 

producers and began extracting bitumen in 

1973. Currently, its Syncrude Project leases 

three mines near Fort McKay and it extracts 

bitumen deposits using in situ and open pit 

mining extraction techniques. It sends its 

product by pipeline to three Edmonton area 

refinieries and to refineries in Canada and the 

U.S. Through its majority owner, Canadian Oil 

Sands, Ltd., Syncrude signed a long-term 

contract with KM's Trans Mountain Pipeline. 

http://www.syncrude.ca/users/fol

der.asp?FolderID=5753

Tesoro Refining & 

Marketing 

Company

Tesoro is an oil refiner with seven refineries in 

the Western United States, including one in 

Anacortes, WA. Tesoro signed a long-term 

contract with KM's Trans Mountain Pipeline.

http://www.tsocorp.com/TSOCorp

/ProductsandServices/Locations/

RefineryLocations/index.htm

Total E&P Canada 

Ltd.

Total E&P Canada extracts bitumen at its 

Surmont, Joslyn, Fort Hills, and Northern Lights 

reserves and upgrades the bitumen at its own 

Voyageur Upgrader. E&P also has assets 

unexplored at this time, known as Asphalt 

Creek and Griffon. It has signed a long-term 

contract with KM's Trans Mountain Pipeline

http://www.total-epcanada.com/upstream/upstream.a

sp

Valero

Valero is the world's largest independent 

petroleum refiner. It has committed to taking 

on at least 100,000 b/d from the Keystone XL. 

http://www.nationaljournal.com/e

nergy/u-s-oil-giants-poised-togain-on-keystone-pipeline20110804
120

Individual/

Organization Description of Involvement Additional Information

Pipeline Operators

Enbridge

Enbridge's oil sands pipeline infrastructure 

connects six producing oil sands projects. It also 

operates contract storage facilities for oil sands 

products. Enbridge is currently sending oil 

sands products into the U.S. through its Line 6B 

pipeline and has proposed to increase its 

capacity through the construction of the 

Northern Gateway Project and the Line 9 

Reversal. 

http://www.enbridge.com/Media

Centre/News/regionaloilsandsAA

G.aspx

http://www.reuters.com/article/

2012/05/17/enbridgeidUSL4E8GH0H820120517

Kinder Morgan

Kinder Morgan is a Texas-based pipeline 

operator that is poised to expand its Trans 

Mountain pipeline from Alberta to Vancouver in 

order to increase its capacity to transport oil 

sands products. 

http://www.kindermorgan.com/i

nvestor/presentations/013013_K

MCanada.pdf 

http://www.kindermorgan.com/b

usiness/canada/tmx_expansion.cf

m

TransCanada

TransCanada is the Keystone pipeline operator 

and is bidding to expand the Keystone pipeline 

from Alberta, Canada to Houston, Texas. It 

currently delivers to refineries in Wood River 

and Patoka, Illinois and Cushing, Oklahoma. Its 

current capacity is 590,000 b/d.

http://www.transcanada.com/10

0.html
121

Individual/

Organization Description of Involvement Additional Information

Rail Companies

Canadian National 

Rail

Canadian National Rail (CN) has a rail yard in 

Fort McMurray, giving them direct access to 

northern Alberta oil sands products. Their 

network has direct access to Peace River and 

Cold Lake deposits. 

http://www.cn.ca/en/shippingnorth-america-alberta-oilsands.htm

Canadian Pacific 

Rail

Canadian Pacific Rail (CPR) directly serves the 

Edmonton/Fort Saskatchewan area. They have 

a direct route to the pipeline 

injection/terminating points at Hardisty and 

Edmonton. CPR also brings diluent to the 

pipeline terminal facilities at these locations. 

http://www.cpr.ca/en/ship-withcp/where-you-can-ship/oilsands/Pages/default.aspx

Burlington 

Northern Santa Fe 

(BNSF)

Owned by Warren Buffet, BNSF is taking 

advantage of the delay in pipeline construction 

by becoming a more politically stable way to 

transport oil sands to refineries and beyond. 

BNSF is currently allowing CNR and CPR to use 

their tracks to transport oil sands products into 

the U.S.

http://www.bloomberg.com/new

s/2012-01-23/buffett-sburlington-northern-amongwinners-in-obama-rejection-ofpipeline.html

Union Pacific

Union Pacific Railroad operates in 23 states 

across the Western two-thirds of the U.S. Its 

network is currently set up to handle oil sands 

products and to deliver oil sands crude to 

refineries in Texas and Oklahoma.

http://www.uprr.com/customers

/chemical/attachments/crude/cr

ude_map.pdf

CSX Transportation

CSX has an extensive rail network in the Eastern 

U.S. Although it currently is not transporting oil 

sands products, it is in the position to do so if 

pipeline construction is further delayed.

http://www.csx.com
122

Individual/

Organization Description of Involvement Additional Information

Industry Associations

API

The American Petroleum Institute (API) is an 

American trade association that represents all 

aspects of the oil and natural gas industry. It 

also provides information to the general public 

about oil sands products and their uses. 

http://www.api.org/oil-andnatural-gas-overview/explorationand-production/oil-sands.aspx

CAPP

The Canadian Association of Petroleum 

Producers (CAPP) represents companies that 

explore, develop, and produce natural gas or oil 

throughout Canada. It provides information and 

resources to its member organizations and also 

to the general public. 

http://www.capp.ca/canadaIndust

ry/oilSands/EnergyEconomy/Pages/default.aspx

CEPA

The Canadian Energy Pipeline Association 

(CEPA) works with its members on the many 

issues associated with moving oil by pipeline. 

Specifically, CEPA makes information available 

on the corrosivity of diluted bitumen in 

pipelines.

http://www.cepa.com/5-morefacts-to-know-about-dilutedbitumen

COSIA

Canada's Oil Sands Innovation Alliance (COSIA) 

is an alliance of oil sands producers that focuses 

on accelerating the pace of improvement in 

environmental performance in Canada's oil 

sands through collaborative action and 

innovation. 

http://www.cosia.ca

OSDG

The Oil Sands Developers Group (OSDG) is an 

industry-funded nonprofit that represents oil 

sands operators and developers. Its members 

work in cooperation with other stakeholders to 

address issues related to oil sands development 

and to communicate information on oil sands 

activity. 

http://www.oilsandsdevelopers.ca
123

Individual/

Organization Description of Involvement Additional Information

U.S. Regulatory Agencies

U.S. Coast Guard

The U.S. Coast Guard (USCG) is in charge of 

facilitating all spill response efforts in coastal 

waters and the Great Lakes. With the proposed 

increase in oil sands transport, the USCG is 

concerned with increases in oil tanker traffic in 

British Columbia and Washington. Washington 

State has five major petroleum refineries which 

could receive oil sands products. As a result, the 

USCG will study the risk of transporting oil 

through the Salish Sea waters. This is mostly in 

response to the proposed Kinder Morgan Trans 

Mountain pipeline expansion. 

http://www.cbc.ca/news/canada/

story/2013/01/06/bc-oil-tankertraffic-review.html

Alaska Department 

of Environmental 

Conservation

If the Northern Gateway pipeline were 

approved, Alaska would see an increase in oil 

tankers coming through its coastal waters. It 

also has the potential to see oil sands products 

traveling to Valdez by rail. The Alaska 

Department of Environmental Conservation is 

the agency in Alaska that works to prevent, 

prepare, and respond to oil spills.

http://www.dec.state.ak.us/spar/i

ndex.htm

Federal Railroad 

Administration

Under the DOT, the Federal Railroad 

Administration (FRA) is in charge of regulating 

all railcars traveling throughout the U.S. Since 

this is likely method of transport for oil sands 

products, FRA is a pertinent regulatory agency 

in the oil sands discussion. 

http://www.fra.dot.gov/

Maine Department 

of Environmental 

Protection

There is a strong possibility that oil sands 

products will/is being transported to Maine's oil 

refineries. Maine's Department of 

Environmental Protection is in charge of 

enforcing the state's environmental laws. 

Therefore, it has a stake in understanding how 

the transport of oil sands products could 

potentially affect Maine's natural resources. 

http://www.maine.gov/dep/spills

/index.html
124

Individual/

Organization Description of Involvement Additional Information

U.S. EPA

The U.S. Environmental Protection Agency 

(EPA) is in charge of responding to all inland 

spills and is also the regulatory agency 

commenting on TransCanada's Keystone XL 

Environmental Impact Statement. EPA was the 

key regulatory agency involved in the Marshall, 

Michigan spill in 2010. 

http://yosemite.epa.gov/oeca/we

beis.nsf/(PDFView)/20100126/$f

ile/20100126.PDF

http://www.epa.gov/region05/cle

anup/kalproject/index.htm

U.S. PHMSA - Office 

of Pipeline Safety

The U.S. Pipeline and Hazardous Materials 

Safety Administration, a subagency within the 

U.S. Department of Transportation (DOT), is in 

charge of regulating pipelines in the U.S. 

http://phmsa.dot.gov/about

U.S. State 

Department

The U.S. State Department approves pipelines 

that cross international borders. This means 

that the Keystone XL will not be constructed 

without the State Department's approval.

http://www.keystonepipelinexl.state.gov

Washington's 

Department of 

Ecology

The Washington State Department of Ecology 

(DOE) is mostly concerned with the potential 

increase in tanker traffic in Washington waters 

due to increased production of oil sands 

products and the potential for these products to 

be shipped out of British Columbia. The DOE 

estimates that about 11% of the gasoline that is 

refined and consumed in Washington is a 

derivative of oil sands. 

http://www.ecy.wa.gov/programs

/spills/about_us/SPPR%202012-

2013%20Program%20Plan%20(fi

nal).pdf 

http://www.ecy.wa.gov/climatech

ange/docs/fuelstandards_112009

_presentation.pdf

http://dep.ky.gov/Pages/Spills.as

px
125

Individual/

Organization Description of Involvement Additional Information 

Canadian Governmental Bodies

Alberta Energy

Alberta Energy oversees Alberta's non-renewable 

resources. Specifically, it operates the Oil Sands 

Division, which provides administrative and 

regulatory services for the Oil Sands Royalty 

Regulations, Oil Sands Tenure Regulation, and Crown 

and individual agreements to ensure that Alberta 

receives appropriate royalties and rentals from oil 

sands development.

http://www.energy.alberta.c

a/ourbusiness/oilsands.asp

Canada's Federal 

Government

Oil sands development adds employment 

opportunities and contributes to Canada's economic 

growth. As a result, conservative Prime Minister 

Stephen Harper has made developing oil sands a 

national priority and has publically expressed his 

support for the Northern Gateway pipeline and the

Trans Mountain (TM) expansion.

http://www.vancouversun.c

om/business/Northern+Gate

way+pipeline+vital+Canada+

interests+Stephen/7053312

/story.html

Canada's National 

Energy Board

The National Energy Board (NEB) regulates 

pipelines, energy development, and trade at the 

interprovincial and international level. Therefore, 

NEB's approval is required for any oil pipeline that 

crosses into the U.S. (Keystone XL) or crosses 

provincial boundaries (Northern Gateway, TM 

Expansion, Line 9).

http://www.nebone.gc.ca/clfnsi/rthnb/whwrndrgvrnnc/r

rspnsblt-eng.html

Environment 

Canada

Environment Canada's mandate is to preserve the 

quality of the natural environment and coordinate 

environmental policies and programs at the federal 

level. It is currently the main resource for scientific 

research performed on the behavior of oil sands.

http://www.ec.gc.ca/inrenwri/default.asp?lang=En&n

=D974A85E-1

Government of 

Alberta

Given that the oil sands reserves are for the most part 

contained in Alberta, the Alberta Government is 

integral in the management and development of oil 

sands.

http://www.oilsands.alberta.

ca

Government of 

British Columbia

The Northern Gateway pipeline and Kinder Morgan's 

TM Expansion affect British Columbia residents. 

There is a large constituency in the province that 

oppose both the pipelines. However, the Premier 

Christy Clark sees the export of oil sands products 

from B.C. ports as a potential economic boost and a 

source of significant employment opportunities.

http://www.vancouversun.c

om/business/Clark+likens+p

otential+Alberta+oilsands/7

698187/story.html
126

Individual/

Organization Description of Involvement Additional Information

Environmental Groups

Forest Ethics

Forest Ethics is working to reduce the demand for 

oil sands products in the U.S. Specifically, the 

organization is focusing its work on the 

communities surrounding U.S. oil sands refineries.

http://forestethics.org/tar-sands

Living Ocean 

Society

The Living Ocean Society is an environmental 

group in Canada that is concerned with marine 

conservation issues. They have been vocal about 

their concerns regarding the state of response 

technologies that could potentially clean up a 

bitumen-related spill.

http://ecowatch.org/2012/cond

emns-announcement/

NRDC

The NRDC is leading the charge against the import 

of oil sands products into the United States. 

Particularly, they have produced a number of antiKeystone XL reports.

http://www.nrdc.org/energy/tar

sandssafetyrisks.asp

NWF

The National Wildlife Federation (NWF) is mostly 

concerned with the methods used to extract 

bitumen and the potential for adverse wildlife 

impacts if a spill occurs. 

http://www.nwf.org/What-WeDo/Energy-and-Climate/Drillingand-Mining/Tar-Sands.aspx

Sierra Club

The Sierra Club has helped organize a number of 

anti-oil sands demonstrations in Canada and is 

specifically working with First Nations to bring 

their concerns to the table. 

http://www.sierraclub.org/dirtyf

uels/tar-sands/default.aspx

The Pembina 

Institute

Oil sands, specifically the greenhouse gases 

associated with development, is one of the Pembina 

Institute's focus areas. It has produced a number of 

reports regarding the responsible development of 

oil sands in Alberta.

http://www.pembina.org/oilsands

Other 

Environmental 

Groups addressing 

oil sands 

development 

include, but are not 

limited to:

Greenpeace Canada, Sierra Club Canada, David 

Suzuki Foundation, Alberta Wilderness Association, 

Environmental Defense Canada, Dogwood Institute, 

West Coast Environmental Law, Indigenous 

Environmental Network, Oil Change International, 

350.org, Energy Action Coalition, Climate Action 

Network Canada, Equiterre, Respecting Aboriginal 

Values and Environmental Needs (RAVEN), 

SumOfUs, LeadNow.ca, Ecojustice, 

DeSmogBlog.com
127

Individual/

Organization Description of Involvement Additional Information

First Nations & Native American Tribes

Chipewyan

The Chipewyan's lands sit in the heart of the 

Alberta oil sands. The Chipewyan launched a 

constitutional challenge based on Treaty 8 

against Shell Canada, which is looking to expand 

their Jackpine oil sands mine into the 

Chipewyan's traditional territories. The 

Chipewyan are arguing that Shell failed to 

adequately consult them, violating treaty rights. 

The Chipewyan also state that they are 

experiencing adverse health effects as a result of 

living downstream from the oil sands. 

http://indiancountrytodaymedian

etwork.com/article/athabascachipewyan-launch-treaty-8-

challenge-to-shell-canada-overoil-sands-137632

http://www.tarsandswatch.org/d

epth-fort-chipewyan

Cree

The Beaver Lake Cree Nation hunts and fishes in 

and around the Athabasca River. The Cree 

Nation argues that oil sands development is 

destroying the habitat that the animals and fish 

they hunt depend on. They are currently in a 

legal battle with the Alberta Government with a 

trial date set for early 2015. 

http://www.raventrust.com/beav

erlakecree.html

Dene

The Dene Nation is downstream from Alberta's 

oil sands and depends on the Athabasca River as 

part of its livelihood. They oppose any new 

pipelines and expansion of oil sands 

development because of the potential negative 

effects it may have on its traditional way of life. 

http://www.nnsl.com/northernnewsservices/stories/papers/oct21_11

pip-nwt.html

Haida

The Haida Nation is opposed to the Northern 

Gateway pipeline and was part of the NEB 

hearings in Edmonton. The pipeline route would 

go through Haida land. 

http://www.qciobserver.com/Arti

cle.aspx?Id=5631

Haisla

Enbridge's Northern Gateway pipeline would 

cross Haisla's land. The Haisla Nation is opposed 

to the pipeline, resulting in legal questions 

about whether Enbridge will be able to build the 

pipeline through Haisla's land. 

http://www.theglobeandmail.com

/report-on-business/industrynews/energy-and-resources/oilsands-pipeline-hits-its-highesthurdle/article1357847/

Lakota

The Lakota Nation actively opposes the 

transport of oil sands products through its 

lands. For example, in 2012 the Lakota created a 

human blockade to stop oil sands pipeline 

trucks from entering their territory. 

http://colorlines.com/archives/2

012/03/lakota_indians_block_key

stone_xl_pipeline_trucks_from_ent

ering_reservation_in_sixhour_standoff.html
128

Individual/

Organization Description of Involvement Additional Information

Makah

The Makah Nation is active in oil spill 

preparedness and is concerned with the 

potential tanker traffic increase in the Strait of 

Juan de Fuca. The Makah Nation also provided 

George Washington University (GWU) data for 

GWU's vessel traffic risk assessment.

http://www.uscg.mil/proceedings

/spring2010/articles/51_Bowech

op_MakahTribalCouncilOfficeOffic

eOfMarineAffairs.pdf

http://www.eisgatewaypacificwa.

gov/sites/default/files/content/fil

es/Makah_Tribal_Council.pdf

Métis

The Métis community sits in the heart of the 

next wave of oil sands development in Northern 

Alberta. They recently signed a deal with 

Cenovus Energy that will give 300 community 

members benefits estimated to be worth $40 to 

$60 million over the next 40 years. 

http://www.aawgecdev.ca/dealbetween-metis-community-oilssands-firm-a-turning-poin.html

Nisga'a

Though the pipeline will not run through 

Nisga'a land, the Nisga'a Nation opposes the 

pipeline due to concerns over increased tanker 

traffic. 

http://www.cbc.ca/news/canada/

britishcolumbia/story/2012/02/17/bccullen-enbridge-hearing.html

Sioux

The Yankton Sioux Reservation is located in 

South Dakota. The Sioux Nation hosted the 

historical event, “Gathering to Protect the 

Sacred From the Tar Sands and Keystone XL," 

where those attending signed an international 

treaty to block the Keystone XL. 

http://www.ienearth.org/tribesand-allies-gather-on-yanktonsioux-reservation-to-oppose-thetar-sands-and-keystone-xlpipeline/

Squamish

The Squamish protested the Kinder Morgan 

expansion in 2012 by canoeing from Ambleside 

to Cates Park to showcase the sanctity of the 

ocean. 

http://dirtyoilsands.org/news/art

icle/squamish_and_tsleil_waututh_

paddle_to_protest_kinder_morgan_

pipeline

Wet'suwet'en

The Wet'suwet'en is opposed to oil sands 

products being transported over their land. 

Recently, the Wet'suwet'en have reaffirmed 

their declaration of "No Enbridge Northern 

Gateway Pipeline on Wet'suwet'en Territory."

http://www.wetsuweten.com/me

dia-centre/news/informationclarification-around-theproposed-northern-gatewaypipeline
129

Individual/

Organization Description of Involvement Additional Information

Coastal First 

Nations

Coastal First Nations is an alliance of First 

Nations on British Columbia's North and Central 

Coast and Haida Gwaii. The Coastal First Nations 

include Wuikinuxv Nation, Heiltsuk, 

Kitasoo/Xaixais, Nuxalk Nation, Gitga'at, 

Metlakatla, Old Massett, Skidegate, and Council 

of the Haida Nation. In March 2010, the Coastal 

First Nations signed the Coastal First Nation 

Declaration, which bans oil sands pipelines and 

tankers on the North Coast. 

http://wcel.org/sites/default/files

/First%20Nations%20that%20ha

ve%20declared%20opposition%2

0to%20proposed%20Enbridge%2

0tanker%20&%20pipeline%20pr

oject.pdf

http://www.coastalfirstnations.ca

/sites/default/files/cfn-filespublic/oil%20tanker%20impacts_

1.pdf

Individual/

Organization Description of Involvement Additional Information 

Other Stakeholders

Landowners in 

South Dakota, 

Montana, Kansas, 

Oklahoma, 

Nebraska, and 

Texas

Landowners along the proposed Keystone XL 

route have mixed opinions about the pipeline 

being routed through their land. 

http://billingsgazette.com/news/s

tate-andregional/montana/landownershave-mixed-views-of-keystonexl/article_1031db2c-fd18-5c8d8250-e1c473ac5ee9.html

Regional Aquatics 

Monitoring 

Program (RAMP)

RAMP is currently engaged in the creation of a 

new monitoring system for the Athabasca oil 

sands. 

http://athabasca.riverawarenesski

t.org/ramp/news.aspx?nid=25

The Prince William 

Sound Regional 

Citizens Advisory 

Council (RCAC)

RCAC is an independent non-profit corporation 

that promotes the environmentally safe 

operations of the Alyeska Pipeline marine 

terminal in Valdez. It has an OPA mandate to 

build trust and provide citizen oversight of 

environmental compliance by oil terminals and 

tankers. With the increase in oil sands 

transportation, the RCAC will have an 

interested in the increased tanker activity in 

their region. 

http://www.pwsrcac.org/about/in

dex.html

*Note: This is not an exhaustive list, but it hopefully reveals the range of stakeholders 

participating in the oil sands debate 
130

9.2 Appendix 2: Known Characteristics and Data Ranges for Alberta Oil Sands 

Products

Product: API 

Gravity

Density 

(g/cm^3)

Viscosity 

(cP;Temp)

Sulfur Content 

(weight %) TAN Pour Point Benzene (ppm)

Athabasca 

Bitumen 7.7-9 1.011-1.0133 (15.56C)

19000-

>300000(15C) 4.41-5.44 3

Cold Lake 

Bitumen 9.8-13.2 0.977-1.002(15C) 235000 4.11-6.9 0.97 (-4)-9

Cold Lake 

Blend 22.6 0.9172-0.9177(15C) 150(15C) 3.6-4.72 0.8 (-45)-(-46) 1510

Cold Lake 

Diluent 69.3 0.704(15C) 1(15C) 0.25 < -75 11600

Enbridge 

Diluent Specs 0.6-0.8(15C) max = 2(7.5C) 0.5 1.17

Bitumen 5.4 1290254.1(25C) 4.4 72.9

Heavy Oil 16.3 100947(25C) 2.9 19.7

Medium Oil 22.4 34(25C) 1.6 8.6

Conventional 

Oil 38.1 13.7(25C) 0.4 16.3

Product: Pour Point Benzene 

(ppm)

Total VOC 

(ppm)

Oil/Salt Water 

Interfacial 

Tension 

(mN/m)

Oil/Fresh 

Water 

Interfacial 

Tension 

(mN/m)

Aqueous 

Solubility 

(mg/L)

Athabasca 

Bitumen

Cold Lake 

Bitumen (-4)-9

Cold Lake 

Blend (-45)-(-46) 1510 10500 28.1 at 0 °C, 16.3 at 15 °C.

28.3 at 0 °C, 

21.7 at 15 °C.

28 at 25 °C 

(distilled 

water)

Cold Lake 

Diluent < -75 11600 68080 7.5 at 0 °C, 6.8 at 15 °C.

8.3 at 0 °C, 

8.3 at 15 °C.

58 at 25 °C 

(distilled 

water)

Enbridge 

Diluent Specs 1.17

Bitumen 72.9

Heavy Oil 19.7 4891.1

Medium Oil 8.6 8209.2

Conventional 

Oil 16.3 15996.3

Sources: Environment Canada and the Congressional Research Service report (Ramseur et 

al, 2012), (Environment Canada, 2013).
131

9.3 Appendix 3: Analysis of Detection & Monitoring Equipment

Technology Analysis 

Snare Sampler •

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

Used in M/T Athos 1 incident where Bachaquero Venezuelan crude oil spilled

Approximately 100 snare samplers were deployed to measure the spread of 

oil

Specifically used to detect oil at various depths in the water column

Produces time-series data

Many were lost due to strong currents, rough seas, and vandalism

Time and labor intensive

No calibration of the efficacy of sampling and how it might change over time 

(Counterspil Research, 2011; Michel, 2006)

Vessel-Submerged Oil 

Recovery System 

(V-SORS)

Deployed V-SORS in M/T Athos 1 and DBL-152 spills

Difficulties with precise locations

Could detect both pooled and mobile oil moving along bottom

Relatively efficient

Provides spatial data on extent of submerged oil

Can be used in vessel traffic lanes

Good positioning capability with onboard GPS

Time and labor intensive

Susceptible to snagging on bottom

Requires use of white snare, which has to be special ordered (Counterspil 

Research, 2011; Michel, 2006)

Side-scan sonar data Used in DBL-152 and M/T Athos 1

Provided good spatial coverage and visualization of large accumulations and 

bottom features

Effectiveness diminished as the oil spread and the water became rough

Slow turn around time (days) to validate oil location

Can be used to identify areas of potential accumulation

More successful in detecting the trenches and other bottom features that 

contained the pooled oil instead of the oil itself (Counterspil Research, 2011; 

Michel, 2006)

RoxAnn Used during DBL-152 with the purpose of differentiating seafloor bottoms

Limited use due to its narrow detection range in relation to the patchiness of 

submerged oil and the large search size

Less accurate in muddy substrates (Michel, 2006; Counterspil Research, 

2011)

Remotely-operated 

underwater video

Used in DBL-152

Successfully provided estimates of frequency and size of oil accumulations

Provides a record for review by others

Could not always determine exact position

Effective with visibility exceeding 0.5 meters, but it does not generate a wide 

view

Small survey swath because of visibility issues (Counterspil Research, 2011)

Sorbents attached to 

weights

Ineffective

Weight of the device pushed the oil away, as seen in the M/T Athos spill 

(Counterspil Research, 2011)
132

Sorbent drops and 

sediment cores

• Results can be used immediately

• Low tech solution

• Not effective for mobile oil in the water column

• Very slow and labor intensive

• Rough water conditions restricted vessel operations

• Could not safely work in active vessel traffic lanes (Michel, 2006)

Snare Sentinels • Effective in the DBL-152 spill, but were determined to be too time and laborintensive for widespread use

• High loss rates (Counterspil Research, 2011; Michel, 2006)

Airborne Hyperspectral 

fluorescent LiDar

• Used in Deepwater Horizon spill

• Proved successful in detecting oil suspended in the top few meters below the 

water surface

RESON Sonar System • Tested by Coast Guard.

• Positively identified 87% of sunken oil targets.

• Had a false alarm rate of 24% (Hansen, Fitzpatrick, Herring, & VanHaverbeke, 

2009)

EIC Fluorosensor • Tested by Coast Guard.

• Can be attached to ROVS or other platforms

• GIS input fluctuated and direct mapping was not possible. (Hansen et al., 

2009)

Side-looking Airborne 

Radar, UV, & IR

• Unable to penetrate water
133

9.4 Appendix 4

State Stated Capacity (Personnel & Equipment)

Illinois •

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

EPA Personnel located in Springfield, Collinsville, and Des Plaines

Indiana On Scene coordinators (OSC) in Evansville and South Bend

Six OSC in Indianapolis

Each OSC is supplied with booms and pads

One equipment trailer

One Command trailer

Three zodiac-style boats

One Airboat

Four boats that patrol Lake Michigan

Intra-red equipment

Michigan Personnel located in Lansing, Warren, Jackson, Kalamazoo, Grand Rapids, Bay City, 

Cadillac, Gwinn, Detroit, Gaylord, Newberry, Crystal Falls, and Calumet

Minnesota Relies on two major spill response contractors and several smaller contractors

All major contractors have headquarters in Duluth with some response equipment

Duluth Fire Department and Duluth Safety Department of the U.S. Coast Guard also have 

response equipment

New York Maintains approximately 100 Spill Response vehicles located in nine regions

Ohio EPA personnel are equipped with testing kits, booms, pads, and other sorbents

Ontario Government agencies in Ontario do not maintain equipment to perform spill recovery 

operations

Largest spill cleanup response organization is ECRC

ECRC will most likely be deployed during a spill in the Great Lakes

Pennsylvania Three vehicles dedicated to emergency response

Emergency response members have safety gear and limited containment supplies

Québec Specialized equipment

Flammable gas detectors

PHD Ultra mulitgas detectors. 

Wisconsin 8 containment booms along Lake Michigan, Lake Superior, and the Mississippi River

Department of Natural Resources has zone contracts with private companies to respond 

to all types of hazardous material spills

2 FLIR Units (infrared detection)
134

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U.S. DEPARTMENT OF COMMERCE 

Penny Pritzker, Secretary

National Oceanic and Atmospheric Administration 

Kathryn D. Sullivan, Ph.D.

Acting Under Secretary of Commerce for Oceans and Atmosphere, 

and Acting Administrator

National Ocean Service 

Holly A. Bamford, Ph.D.

Assistant Administrator for Ocean Services and Coastal Zone Management